[House Hearing, 110 Congress]
[From the U.S. Government Publishing Office]


 
                      PROSPECTS FOR ADVANCED COAL 
               TECHNOLOGIES: EFFICIENT ENERGY PRODUCTION, 
                    CARBON CAPTURE AND SEQUESTRATION 

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

                                HEARING

                               BEFORE THE

                       SUBCOMMITTEE ON ENERGY AND
                              ENVIRONMENT

                  COMMITTEE ON SCIENCE AND TECHNOLOGY
                        HOUSE OF REPRESENTATIVES

                       ONE HUNDRED TENTH CONGRESS

                             FIRST SESSION

                               __________

                              MAY 15, 2007

                               __________

                           Serial No. 110-29

                               __________

     Printed for the use of the Committee on Science and Technology


     Available via the World Wide Web: http://www.science.house.gov

                                 ______

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                  COMMITTEE ON SCIENCE AND TECHNOLOGY

                 HON. BART GORDON, Tennessee, Chairman
JERRY F. COSTELLO, Illinois          RALPH M. HALL, Texas
EDDIE BERNICE JOHNSON, Texas         F. JAMES SENSENBRENNER JR., 
LYNN C. WOOLSEY, California              Wisconsin
MARK UDALL, Colorado                 LAMAR S. SMITH, Texas
DAVID WU, Oregon                     DANA ROHRABACHER, California
BRIAN BAIRD, Washington              ROSCOE G. BARTLETT, Maryland
BRAD MILLER, North Carolina          VERNON J. EHLERS, Michigan
DANIEL LIPINSKI, Illinois            FRANK D. LUCAS, Oklahoma
NICK LAMPSON, Texas                  JUDY BIGGERT, Illinois
GABRIELLE GIFFORDS, Arizona          W. TODD AKIN, Missouri
JERRY MCNERNEY, California           JO BONNER, Alabama
PAUL KANJORSKI, Pennsylvania         TOM FEENEY, Florida
DARLENE HOOLEY, Oregon               RANDY NEUGEBAUER, Texas
STEVEN R. ROTHMAN, New Jersey        BOB INGLIS, South Carolina
MICHAEL M. HONDA, California         DAVID G. REICHERT, Washington
JIM MATHESON, Utah                   MICHAEL T. MCCAUL, Texas
MIKE ROSS, Arkansas                  MARIO DIAZ-BALART, Florida
BEN CHANDLER, Kentucky               PHIL GINGREY, Georgia
RUSS CARNAHAN, Missouri              BRIAN P. BILBRAY, California
CHARLIE MELANCON, Louisiana          ADRIAN SMITH, Nebraska
BARON P. HILL, Indiana               VACANCY
HARRY E. MITCHELL, Arizona
CHARLES A. WILSON, Ohio
                                 ------                                

                 Subcommittee on Energy and Environment

                   HON. NICK LAMPSON, Texas, Chairman
JERRY F. COSTELLO, Illinois          BOB INGLIS, South Carolina
LYNN C. WOOLSEY, California          ROSCOE G. BARTLETT, Maryland
DANIEL LIPINSKI, Illinois            JUDY BIGGERT, Illinois
GABRIELLE GIFFORDS, Arizona          W. TODD AKIN, Missouri
JERRY MCNERNEY, California           RANDY NEUGEBAUER, Texas
MARK UDALL, Colorado                 MICHAEL T. MCCAUL, Texas
BRIAN BAIRD, Washington              MARIO DIAZ-BALART, Florida
PAUL KANJORSKI, Pennsylvania             
BART GORDON, Tennessee               RALPH M. HALL, Texas
                  JEAN FRUCI Democratic Staff Director
            CHRIS KING Democratic Professional Staff Member
        MICHELLE DALLAFIOR Democratic Professional Staff Member
         SHIMERE WILLIAMS Democratic Professional Staff Member
         ELAINE PAULIONIS Democratic Professional Staff Member
          ADAM ROSENBERG Democratic Professional Staff Member
          ELIZABETH STACK Republican Professional Staff Member
                    STACEY STEEP Research Assistant


























                            C O N T E N T S

                              May 15, 2007

                                                                   Page
Witness List.....................................................     2

Hearing Charter..................................................     3

                           Opening Statements

Statement by Representative Nick Lampson, Chairman, Subcommittee 
  on Energy and Environment, Committee on Science and Technology, 
  U.S. House of Representatives..................................     6
    Written Statement............................................     6

Statement by Representative Bob Inglis, Ranking Minority Member, 
  Subcommittee on Energy and Environment, Committee on Science 
  and Technology, U.S. House of Representatives..................     7
    Written Statement............................................     8

Prepared Statement by Representative Jerry F. Costello, Member, 
  Subcommittee on Energy and Environment, Committee on Science 
  and Technology, U.S. House of Representatives..................     8

                               Witnesses:

Mr. Carl O. Bauer, Director, National Energy Technology 
  Laboratory, U.S. Department of Energy
    Oral Statement...............................................     9
    Written Statement............................................    11
    Biography....................................................    14

Dr. Robert J. Finley, Director, Energy and Earth Resources 
  Center, Illinois State Geological Survey
    Oral Statement...............................................    15
    Written Statement............................................    17
    Biography....................................................    18

Mr. Michael W. Rencheck, Senior Vice President, Engineering, 
  Projects and Field Services, American Electric Power
    Oral Statement...............................................    19
    Written Statement............................................    20
    Biography....................................................    33

Mr. Stuart M. Dalton, Director, Generation, Electric Power 
  Research Institute
    Oral Statement...............................................    34
    Written Statement............................................    34
    Biography....................................................    43

Mr. Gardiner Hill, Director, CCS Technology, Alternative Energy, 
  BP
    Oral Statement...............................................    44
    Written Statement............................................    46

Discussion
  Carbon Sequestration Risks.....................................    48
  Regulatory Requirements........................................    49
  Carbon Sequestration Sites.....................................    50
  Carbon Dioxide Transportation..................................    50
  Carbon Sequestration Atlas.....................................    51
  CCS Technology Readiness.......................................    52
  Other Uses for CO2..................................... 55
  Western Regional Partnerships..................................    55
  Funding Concerns...............................................    57
  Carbon Capture for Coal to Liquids.............................    58
  Efficiency.....................................................    60
  Basic Organic Chemistry........................................    63
  Carbon Capture.................................................    63
  H.R. 1933, the Department of Energy Carbon Capture and Storage 
    Research, Development, and Demonstration Act.................    65
  More on Carbon Sequestration Risks.............................    67

             Appendix 1: Answers to Post-Hearing Questions

Mr. Carl O. Bauer, Director, National Energy Technology 
  Laboratory, U.S. Department of Energy..........................    70

             Appendix 2: Additional Material for the Record

H.R. 1933, Department of Energy Carbon Capture and Storage 
  Research, Development, and Demonstration Act of 2007...........    74


PROSPECTS FOR ADVANCED COAL TECHNOLOGIES: EFFICIENT ENERGY PRODUCTION, 
                    CARBON CAPTURE AND SEQUESTRATION

                              ----------                              


                         TUESDAY, MAY 15, 2007

                  House of Representatives,
            Subcommittee on Energy and Environment,
                       Committee on Science and Technology,
                                                    Washington, DC.

    The Subcommittee met, pursuant to call, at 1:05 p.m., in 
Room 2318 of the Rayburn House Office Building, Hon. Nick 
Lampson [Chairman of the Subcommittee] presiding.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]

                            hearing charter

                 SUBCOMMITTEE ON ENERGY AND ENVIRONMENT

                  COMMITTEE ON SCIENCE AND TECHNOLOGY

                     U.S. HOUSE OF REPRESENTATIVES

                      Prospects for Advanced Coal

               Technologies: Efficient Energy Production,

                    Carbon Capture and Sequestration

                         tuesday, may 15, 2007
                          1:00 p.m.-3:00 p.m.
                   2318 rayburn house office building

Purpose

    On Tuesday, May 15, 2007 the Subcommittee on Energy and Environment 
of the Committee on Science and Technology will hold a hearing to 
receive testimony on the advancement of coal technologies and carbon 
capture and sequestration strategies which will help to reduce the 
emissions of greenhouse gases, in particular, carbon dioxide.
    The Department of Energy has a number of ongoing research and 
development programs designed to demonstrate advanced technologies that 
reduce coal power's carbon emissions. In addition, some industry 
leaders also have begun to invest in advanced coal technologies. The 
Committee will hear testimony from five witnesses who will speak to the 
current research, development, demonstration and ultimate commercial 
application of technologies that enable our power plants to operate 
more efficiently, reduce emissions, and capture carbon for long-term 
storage. They will discuss the technological and economic challenges we 
face in limiting carbon emissions and safely managing the captured 
carbon on a large scale.

Witnesses

        1.  Mr. Carl O. Bauer, Director of the National Energy 
        Technology Laboratory (NETL), a national laboratory owned and 
        operated by the Department of Energy. In his current position 
        as Director of NETL, he oversees the implementation of major 
        science and technology development programs to resolve the 
        environmental, supply and reliability constraints of producing 
        and using fossil resources, including advanced coal-fueled 
        power generation, carbon sequestration, and environmental 
        control for the existing fleet of fossil steam plants.

        2.  Dr. Robert J. Finley, Director Energy and Earth Resources 
        Center for Illinois State Geological Survey with specialization 
        in fossil energy resources. He is currently heading a regional 
        carbon sequestration partnership in the Illinois Basin aimed at 
        addressing concerns with geological carbon management.

        3.  Mr. Michael Rencheck, Senior Vice President for Engineering 
        Projects and Field Services at American Electric Power 
        headquartered in Columbus, Ohio. He is responsible for 
        engineering, regional maintenance and shop service 
        organizations, projects and construction, and new generation 
        development. He will discuss ongoing projects at AEP and can 
        talk to plant efficiencies and retrofitting facilities to 
        capture carbon.

        4.  Mr. Stu Dalton, Director, Generation at the Electric Power 
        Research Institute. His current research activities cover a 
        wide variety of generation options with special focus on 
        emerging generation, coal-based generation, emission controls 
        and CO2 capture and storage. He also helped to 
        create the EPRI Coal Fleet for Tomorrow program.

        5.  Mr. Gardiner Hill, Director of Technology in Alternative 
        Energy Technology, is responsible for BP group-wide aspects of 
        CO2 Capture and Storage technology development, 
        demonstration and deployment. He also is the BP manager 
        responsible for the BP/Ford/Princeton Carbon Mitigation 
        Initiative at Princeton University as well as the BP manager 
        responsible for the BP/Harvard partnership on the Energy 
        Technology Innovation Project. He posses 20 years of technical 
        and managerial experience which is directly relevant to 
        technology, business and project management.

Background

    Approximately 50 percent of the electricity generated in the United 
States is from coal. According to DOE's Energy Information 
Administration (EIA) carbon dioxide emissions in the United States and 
its territories were 6,008.6 million metric tons (MMT) in 2005. In the 
United States, most CO2 is emitted as a result of the 
combustion of fossil fuels. In particular, the electric power sector 
accounts for 40 percent of the CO2 emissions in the U.S., 
according to EIA.
    If we are going to implement policies to reduce greenhouse gas 
emissions associated with the use of coal, what technologies are 
currently available, what technologies need to be developed or 
improved, and what technical challenges must we overcome to meet that 
goal? There are two primary approaches to reducing emissions associated 
with coal-fired power production: increasing the efficiency of coal-
fired plants (through replacement with new plants or retrofitting 
existing plants) and through installation of carbon capture technology 
and transporting CO2 to a permanent storage facility.

CO2 Capture

    Retrofitting existing coal-fired power plants to capture carbon is 
a critical component of any strategy to reduce our emissions of 
greenhouse gases. Carbon capture applications may be installed in new 
energy plants or retrofitted to existing plants. Some outstanding 
issues with retrofitting existing plants include site constraints such 
as availability of land for the capture equipment and the need for a 
long remaining plant life to justify the large expense of installing 
the capture equipment. Another potential barrier to retrofitting is the 
loss in efficiency that can occur due to the energy required to operate 
the carbon-capture equipment.
    The first step in carbon capture and sequestration is to produce a 
concentrated stream of CO2 for capture. Currently, there are 
three main approaches to capture CO2 from large-scale 
industrial facilities or power plants: 1) post-combustion capture, 2) 
pre-combustion capture, and 3) oxy-fuel combustion capture.
    Post-combustion capture process, although not required, involves 
extracting CO2 from the flue gas following combustion of 
fossil fuels. There are commercially available technologies that use 
chemical solvents to absorb the carbon.
    Pre-combustion capture separates CO2 from the fuel by 
combining it with air and/or steam to produce hydrogen for combustion 
and CO2 for storage. The most commonly discussed type of 
pre-combustion capture technology is the gasification method. 
Gasification is a method of taking low-value feedstocks such as coal, 
biomass or petroleum coke and transforming them through a chemical 
process to make high value products such as chemicals or electricity. 
Integrated Gasification Combined Cycle (IGCC)--often discussed as a 
major breakthrough to improve the environmental performance of coal-
based electric power generation--is a form of gasification, which uses 
syngas created from the gasification process as the feedstock, to power 
a combined-cycle turbine used to produce electricity. IGCC has the 
ability to produce a relatively pure stream of CO2 arguably 
making it better suited for carbon capture than a pulverized coal 
plant.
    Oxy-fuel combustion capture uses oxygen instead of air for 
combustion and produces a flue gas that is mostly CO2 and 
water which are easily separated. This technique is considered 
developmental and has not been widely applied for power production, 
mainly because the temperatures that result from the combustion of pure 
oxygen are far too high for typical power plant materials.

CO2 Sequestration

    Geologic sequestration of CO2 is considered the most 
feasible and widely studied method of storage. There are three main 
types of geologic formations: 1) oil and gas reservoirs, 2) deep saline 
reservoirs, and 3) unmineable coal seams.
    When CO2 is injected below 800 meters in a typical 
reservoir, the pressure induces CO2 to behave like a 
relatively dense liquid. This state is known as ``super-critical.'' 
With each of the three methods listed above, CO2 would be 
injected into reservoirs that hold, or previously held liquids or 
gases. In addition, injecting CO2 into deep geological 
formations uses existing technologies that have been primarily 
developed by and used for the oil and gas industry. For these reasons, 
geologic sequestration appears to be a promising carbon storage 
strategy.
    Pumping CO2 into oil and gas reservoirs to boost 
production, a process known as enhanced oil recovery (EOR) is practiced 
by the petroleum industry today. Using EOR for long-term CO2 
storage is beneficial because sequestration costs can be partially 
offset by revenues from oil and gas production. However, the primary 
purpose of CO2 for EOR was not intended to serve the need 
for long-term sequestration of CO2 and the degree to which 
injected CO2 remains in the reservoir in many areas 
utilizing EOR is unknown.
    Depleted or abandoned oil and gas fields are potential candidates 
for CO2 storage because the oil and gas originally trapped 
did not escape for millions of years demonstrating the structural 
integrity of these reservoirs. Because of their value as sources of oil 
and gas, these reservoirs have been mapped and studied and computer 
models have often been developed to understand how hydrocarbons move in 
the reservoir. These models could be applied to predict the potential 
movement of CO2 within these reservoirs.
    Still, there are concerns with using oil and gas reservoirs for 
CO2 storage that stem from the stability of the reservoir 
post-production and the degree of certainty that leakage could be 
prevented.
    A noteworthy project is the Weyburn Project in south-central Canada 
which uses CO2 produced from a coal gasification plant in 
North Dakota for EOR. According to CRS, comprehensive monitoring is 
being conducted at Weyburn.
    Deep saline formations are sedimentary basins saturated with saline 
or briny water that is unfit for human consumption or agricultural use. 
As with oil and gas, deep saline reservoirs can be found onshore and 
offshore. There are advantages of using saline reservoirs for CO2 
sequestration: they are more widespread in the U.S. than oil and gas 
reservoirs and potentially have the largest reservoir capacity of the 
three types of geologic formations being considered for carbon 
sequestration.
    The first commercial-scale operation for sequestering CO2 
in a deep saline reservoir is the Sleipner Project in the North Sea. 
While deep saline reservoirs have huge potential capacity to store 
CO2, there is concern about maintaining the integrity of the 
reservoir because of chemical reactions following CO2 
injection. CO2 can acidify the fluids in the reservoir, 
dissolving minerals such as calcium carbonate, and possibly weakening 
the reliability of the storage site. Increased permeability could allow 
the CO2 to create new pathways that lead to contamination of 
aquifers used for drinking water.
    Many coal seams are unmineable with current technology because the 
coal beds are not thick enough, the beds are too deep, or the 
structural integrity of the coal bed is inadequate for mining. Because 
coal beds are highly permeable they tend to trap gases, such as 
methane, that bind themselves to the coal. CO2 binds even 
more tightly to coal than methane, thus making it possible to store the 
unwanted CO2 and increase the recovery of the valuable 
coalbed methane.

Efficient Energy Production and Retrofitting Existing Coal-fired Power 
                    Plants

    EIA projections show that a two percent increase in coal efficiency 
would exceed all additional renewable power generation through the EIA 
forecast period (2030).
    Raising the efficiency of power plants is part of the debate on how 
best to reduce carbon dioxide emissions. Adopting advanced power 
generating systems could help plant efficiency for coal-fired power 
plants. For example, the Department of Energy's National Energy 
Technology Laboratory (NETL) is developing technologies to ensure 
existing and future coal power systems are more efficient and burn more 
cleanly. Their work includes gasification, advanced combustion, and 
turbine and heat engine technologies. Coal power plants operate at 
approximately a 33 percent efficiency level and NETL is striving to 
develop technologies for a central power plant that is capable of 60 
percent efficiency with near zero emissions by 2020.
    In addition to designing new plants to be more efficient, NETL and 
others are working on technologies that can be utilized to improve the 
efficiency of existing coal-fired power plants. In the short-term, 
options such as converting from sub-critical to super-critical steam 
cycle and combining coal with biomass to fuel plants both offer 
opportunities to lower CO2 emissions from existing coal 
plants.
    Chairman Lampson. This hearing will come to order, and I am 
pleased to welcome our witnesses here today to talk about a 
critical issue: the advancing technologies designed to reduce 
coal power's carbon dioxide emissions.
    I think our panelists will bring a wealth of knowledge to 
share about cleaner production of electricity at both new and 
existing coal-fired power plants, and we have several witnesses 
who will discuss the technical issues regarding long-term 
geological storage of CO2. Again, I welcome our 
witnesses and thank you very much for testifying before the 
Subcommittee this afternoon.
    As many of us know in this room this afternoon, 
approximately 50 percent of the electricity generated in the 
United States is from coal. According to DOE's Energy 
Information Administration, EIA, carbon dioxide emissions in 
the United States and its territories were just over six 
billion metric tons in 2005, and the electric power sector 
generates approximately 40 percent of the Nation's CO2 
emissions.
    Because we will continue to rely on coal for a large 
percentage of our energy consumption for the foreseeable 
future, there is growing national and global interest in 
developing strategies to significantly reduce the billions of 
tons of carbon dioxide released into our atmosphere from this 
source.
    If we are going to implement policies to reduce greenhouse 
gas emissions associated with the use of coal, today's hearing 
will help us better understand how far along we have come in 
meeting this challenge and how much further we may need to go.
    I understand that promising technologies are being 
developed to improve the efficient production of electricity 
from coal-fired power plants which could help to reduce 
CO2 emissions. I look forward to learning more about 
the deployment of technologies that can capture CO2 
from new and existing power plants and keep it out of the 
atmosphere.
    We must advance our technical ability to capture CO2 
and prepare the heat-trapping gas for safe and effective 
storage in geologic formations. Without commercialization of 
carbon capture technologies and effective strategies to 
transport the CO2 from capture to long-term storage, 
we run the risk of profound damages to our climate system.
    I believe that coal will continue to remain a major energy 
source in the United States. I also believe the government, in 
partnership with private industry and universities, can take 
great strides in reducing coal's contribution to global 
warming.
    I look forward to hearing from our panelists about the 
challenges we face to design a carbon capture and sequestration 
strategy that is sensible and meaningful.
    And now, I would like to recognize our distinguished 
Ranking Member, Mr. Inglis of South Carolina, for his opening 
statement.
    [The prepared statement of Chairman Lampson follows:]
              Prepared Statement of Chairman Nick Lampson
    I am pleased to welcome our witnesses here today to talk about a 
critical issue--advancing technologies designed to reduce coal power's 
carbon dioxide emissions.
    I think our panelists bring a wealth of knowledge to share about 
cleaner production of electricity at both new and existing coal-fired 
power plants. And, we have several witnesses who will discuss the 
technical issues regarding long-term geological storage of 
CO2. Again, I welcome our witnesses and thank you for 
testifying before the Subcommittee this afternoon.
    As many of us in this room know, approximately 50 percent of the 
electricity generated in the United States is from coal. According to 
DOE's Energy Information Administration (EIA) carbon dioxide emissions 
in the United States and its territories were just over six billion 
metric tons in 2005, and the electric power sector generates 
approximately 40 percent of the Nation's CO2 emissions.
    Because we will continue to rely on coal for a large percent of our 
energy consumption for the foreseeable future, there is a growing 
national and global interest in developing strategies to reduce 
significantly the billions of tons of carbon dioxide released into our 
atmosphere from this source.
    If we are going to implement policies to reduce greenhouse gas 
emissions associated with the use of coal, today's hearing will help us 
better understand how far along we have come in meeting this challenge 
and how much further we may need to go.
    I understand that promising technologies are being developed to 
improve the efficient production of electricity from coal-fired power 
plants which could help to reduce CO2 emissions. I look 
forward to learning more about the deployment of technologies that can 
capture CO2 from new and existing power plants and keep it 
out of the atmosphere.
    We must advance our technical ability to capture CO2 and 
prepare the heat-trapping gas for safe and effective storage in 
geologic formations. Without commercialization of carbon capture 
technologies and effective strategies to transport the CO2 
from capture to long-term storage, we run the risk of profound damages 
to our climate system.
    I believe that coal will continue to remain a major energy source 
in the United States. I also believe the government, in partnership 
with private industry and universities, can take great strides in 
reducing coal's contribution to global warming.
    I look forward to hearing from our panelists about the challenges 
we face to design a carbon capture and sequestration strategy that is 
sensible and meaningful.

    Mr. Inglis. And I thank the Chairman. Thank you for holding 
this hearing on an important topic.
    As the Chairman just pointed out, we get a lot of our 
electricity from coal, and we have a lot of coal available to 
us, so sequestration seems to be one of the key breakthroughs 
that we need to achieve in order to make efficient or effective 
use of this resource.
    And you know, we have got a case study in South Carolina 
right now. Duke Energy faces a decision of whether to build a 
coal-fired plant or a nuclear power plant, the question of the 
nuclear plant, I think that it would be preferable, frankly, in 
that situation, even though it is very expensive, $6 billion. 
But their probable choice, sounds to me, since I am not 
connected with the company, I guess we don't have to make any 
SEC disclosures based on this, but it seems to me that they are 
probably headed toward the coal-fired plant, which will, 24/7, 
365 days a year, have a CO2 issue associated with 
it. And somehow, we have got to deal with that, and so, this 
panel today, I hope, will help us figure out where the science 
stands with respect to sequestration, and help us know how the 
government might be a partner in funding some research, or in 
being the early adopters or the regulators that would cause 
this technology to advance, and make it so that that plant, if 
it is built as a coal plant, doesn't create the harmful side 
effects that we are all concerned about.
    So, it is good to be here. It is good to have the 
opportunity to have some experts that will help us understand 
the possibilities that are available to us, and Mr. Chairman, I 
look forward to hearing from our witnesses.
    [The prepared statement of Mr. Inglis follows:]
            Prepared Statement of Representative Bob Inglis
    Thank you for holding this hearing, Mr. Chairman.
    Duke Energy faces a dilemma in South Carolina. They would like to 
be producing energy free of CO2 emissions, but because of 
the extensive licensing hurdles of nuclear, and the high costs of wind 
and solar power, Duke has been forced to meet increased energy demand 
by building coal-powered plants. Perhaps if we had clean coal and 
carbon capture technologies readily available and affordable, companies 
like Duke would be able to meet growing energy demand with coal and 
without emissions.
    We are currently consuming coal energy at a rapid pace. We need to 
focus on ways to make that consumption cleaner and more efficient. 
Clean coal and carbon capture and sequestration technologies offer such 
solutions. I hope that we can find ways to encourage the implementation 
of these technologies.
    More importantly, I hope that these technologies will be affordable 
and attractive to U.S. and global industry alike. America can lead the 
way with technological innovation that can be easily integrated into 
existing coal plants worldwide. In addition, the research that will 
soon begin at the FutureGen site, and the construction of IGCC power 
plants, will be vital for pioneering and demonstrating the many 
benefits of clean coal and carbon capture and sequestration 
technologies for other countries.
    The future of renewable energy promises an end to our dependence on 
fossil fuels like oil and coal. But for today, we must work to make 
sure that our coal consumption is as emission-free and energy efficient 
as possible, bringing benefits to both industry and the environment.
    Thank you again for holding this hearing, Mr. Chairman, and I look 
forward to hearing from our witnesses.

    Chairman Lampson. Thank you very much. I ask unanimous 
consent that all additional opening statements submitted by 
Subcommittee Members be included in the record. Without 
objection, so ordered.
    [The prepared statement of Mr. Costello follows:]
         Prepared Statement of Representative Jerry F. Costello
    Mr. Chairman, thank you for calling today's hearing to receive 
testimony on the advancement of coal technologies and carbon capture 
and sequestration strategies.
    I am privileged to represent the 12th Congressional District of 
Illinois, a region rich in coal reserves and mining. Coal plays a vital 
role as an energy source, and the industries involved in the mining, 
transportation and utilization of coal provide thousands of jobs for 
people in Illinois and other parts of the country, in addition to 
economic benefits to many communities across Illinois and the Nation. 
Further, the Clean Coal Research Center at Southern Illinois University 
(SIUC), the State of Illinois and its energy industries are committed 
to the development and application of technologies for the 
environmentally sound use of Illinois coal.
    I believe clean coal technology is part of the solution to 
achieving U.S. energy independence, continued economic prosperity and 
improved environmental stewardship. In February, a group of twenty-
seven Democrats sent a letter to Speaker Pelosi and Majority Leader 
Hoyer stating our strong commitment to advance the deployment of clean 
coal technologies, including carbon capture and sequestration (CCS). In 
order for carbon capture and sequestration technology to become 
commercially viable, the Federal Government must show it is committed 
to the necessary research, development, and demonstration (RD&D). Mr. 
Chairman, as you know, I have been a strong advocate for federal coal 
initiatives and programs. I am focused on increasing the funding levels 
for clean coal research and development (R&D) programs for FY08 because 
coal is going to be the mainstay for electricity generation well into 
the future. I intend to continue to work with my colleagues on both 
sides of the aisle to ensure we continue to advance clean coal 
technology to overcome the technical and economical challenges for 
coal-based power plants.
    There have been several Committee hearings in the House and Senate 
to discuss CCS technology. I am glad we are having today's Subcommittee 
hearing because it is important to clarify that while CCS technology 
will enable our power plants to operate more efficiently and reduce 
emissions, there are challenges to overcome before the utilities or the 
coal industry can deploy CCS technology. The reality is that until CCS 
technology is ready to be deployed at a commercial scale, a mandate 
from Congress requiring industry to cap all carbon dioxide underground 
will shut down coal plants across the country, drive up consumer's 
electricity bills, and convert power generation plants to burn natural 
gas. Given the volatility of the oil and gas market, the instability in 
the Middle East and rising oil and gas prices, we should be moving away 
from policies that place a greater dependence on foreign resources and 
instead, focus on improving clean coal R&D and demonstration projects 
to utilize the natural resources we have here in the U.S. I am 
interested in hearing from our witnesses further on this point.
    With that, again, thank you Chairman Lampson--I look forward to 
hearing from our witnesses.

    Chairman Lampson. It is my pleasure to introduce the 
excellent panel of witnesses that we have here with us this 
afternoon. Mr. Carl Bauer is the Director of the National 
Energy Technology Laboratory at the Department of Energy. He is 
accompanied by Dr. Joseph Strakey, who leads the Strategic 
Center for Coal at the Laboratory.
    Mr. Michael Rencheck is the Senior Vice President of 
Engineering Projects and Field Services for American Electric 
Power. Mr. Stuart Dalton is the Director of Generation at the 
Electric Power Research Institute, and Mr. Gardiner Hill is the 
Director of the CCS Technology and Alternative Energy for 
British Petroleum.
    And at this time, I would yield to my colleague from 
Illinois, Mr. Costello, to introduce our fifth witness, Dr. 
Robert Finley.
    Mr. Costello. Mr. Chairman, I thank you, and I thank you 
for calling this hearing today on this important topic.
    Dr. Robert Finley is the Director of Energy and Earth 
Resources Center for the Illinois State Geological Survey. Dr. 
Finley is the head of a Regional Carbon Sequestration 
Partnership in the Illinois Basin aimed at addressing concerns 
with geological carbon management. We look forward to hearing 
from him today, as well as the other witnesses, and I might add 
that we have had the opportunity to discuss this important 
issue with Dr. Finley in the past, and we look forward to 
hearing his testimony and the testimony of the other witnesses.
    I thank you, Mr. Chairman.
    Chairman Lampson. Thank you, Mr. Costello.
    You will each have five minutes for your spoken testimony. 
Your full written testimony will be included in the record for 
the hearing, and when each of you has completed your testimony, 
we will begin with questions, and each Member will have five 
minutes to question the panel.
    Mr. Bauer, would you begin, please.

   STATEMENT OF MR. CARL O. BAUER, DIRECTOR, NATIONAL ENERGY 
        TECHNOLOGY LABORATORY, U.S. DEPARTMENT OF ENERGY

    Mr. Bauer. Thank you, Mr. Chairman and Members of the 
Committee. I appreciate this opportunity to provide testimony 
on DOE's advanced clean coal technologies and the program for 
carbon capture and storage.
    Our economic prosperity was built upon abundance of fossil 
fuels, and we have approximately a 250 year supply of coal in 
the United States. The continued use of this secure domestic 
resource is critically dependent on developing cost-effective 
technology options to meet our environmental goals, including 
the reduction of carbon dioxide.
    Carbon capture and storage, or CCS, offers a great 
opportunity to reduce these potential emissions, and the U.S. 
and Canada are blessed with an abundance of potential geologic 
storage capacity for CO2. The current facts store 
annual CO2 emissions associated with all current 
energy production and use in North America for a period of 
about 500 years.
    Our coal technology program includes development of 
advanced technologies for pre-combustion or gasification, post-
combustion, and oxy-combustion, multiple pathways to produce 
power and capture CO2, as well as a robust program 
for carbon sequestration. The 2012 program goal is to show that 
we can develop advanced technology to capture and store at 
least 90 percent of the potential CO2 emissions from 
coal-fired power plants, with less than a 10 percent increase 
in the cost of electricity. Commercially available technology 
to do this today would add from 30 to 70 percent to the present 
price of electricity.
    Gasification is a pre-combustion pathway to convert coal 
biomass or carbon containing feedstocks into clean synthesis 
gas for use in producing power, fuel, chemicals, and hydrogen. 
The gasification technologies being developed meet the most 
stringent environmental regulations in any state and provide 
the opportunity for potential efficient capture of 
CO2.
    The Power System Development Facility in Wilsonville, 
Alabama provides a pilot-scale test platform for evaluating 
critical process components. The transport gasifier at the PSDF 
is showing great promise for cost-effective gasification of 
low-rank, high-moisture western coals. Recent successful 
testing of the Stamet dry-feed coal pump indicates a 
breakthrough, allowing coal to be pumped directly into a high-
pressure gasifier, and thus avoiding the need for coal drying 
and complex feeding systems.
    Another major development is the ion transport membrane 
technology. This is a more efficient and lower cost method for 
producing oxygen which is needed for these processes. This 
year, we are testing the robustness of the technology at Air 
Products' Sparrows Point facility.
    Finally, we are successfully testing at Research Triangle 
Institute's warm gas sulfur cleanup system at Eastman 
Chemical's facility in Kingsport, Tennessee. They have a 
gasifier there that uses coal. Since last fall, the test unit 
has performed exceptionally well and achieved extremely low 
sulfur levels.
    The Advanced Turbine Program is developing and testing 
advanced turbine technologies for use of hydrogen as a fuel. A 
key need for zero-emission coal gasification plants. We plan to 
increase the efficiency of these turbines by two to three 
percentage points, while reducing the nitrous oxide emissions 
to ultra-low t parts per million. High temperature solid oxide 
fuel cells are being developed for a variety of applications 
under the SECA program. These fuel cells offer several 
significant advantages to coal-based near-zero-emissions power 
systems, and are focused on operating on coal-derived syngas.
    DOE's carbon sequestration program leverages basic and 
applied research with field verification to assess the 
technical and economic viability of CCS. The key challenges for 
this program are to demonstrate the ability to capture and 
store CO2 in underground geologic formations with 
long-term stability, develop the ability to monitor and verify 
the fate of the CO2, and to gain public and 
regulatory acceptance. DOE's seven Regional Carbon 
Sequestration Partnerships are engaged in a major effort to 
develop and validate the CCS technology in different geologies 
across the U.S.
    DOE also recognizes the importance of the existing fleet of 
coal-fired power plants in meeting energy demand and possible 
future carbon constraints. Research is being pursued to 
dramatically lower the cost of capturing CO2 from 
these plants.
    The FutureGen project is an industry/government partnership 
designed to build and operate a gasification-based, nearly 
emission-free, coal-fired electricity production plant. The 
275-megawatt plant will serve as a large-scale laboratory for 
the validating of the commercial readiness of the technologies 
that are emerging from the base coal R&D pipeline. The 
important data and experience from FutureGen will lead to 
design of the next generation of near-zero-emission coal 
plants, and provide information for industry, financial 
investors, and regulatory partners to understand how better to 
regulate and operate these plants.
    Mr. Chairman and Members of the Committee, this completes 
my statement, and I would be happy to take any questions you 
may have at this time or later. Thank you.
    [The prepared statement of Mr. Bauer follows:]
                  Prepared Statement of Carl O. Bauer
    Thank you Mr. Chairman and Members of the Committee. 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. We 
have approximately a 250-year supply of coal available in the United 
States, at our current consumption rates. Coal-fired power plants 
supply over half of our electricity today; the continued use of this 
secure domestic resource is critically dependent on the development of 
cost-effective technology options to meet our environmental goals, 
including the reduction of carbon dioxide (CO2) emissions.
    Carbon capture and storage (CCS) technologies offer a great 
opportunity to reduce these potential emissions. Fortunately, the 
United States and Canada are blessed with an abundance of potential 
geologic storage capacity. At the current rate of energy production and 
use, we could potentially store all of the associated CO2 
emissions in North America that are produced over the next 175 to 500 
years, according to the geologic storage capacity estimates recently 
made by DOE's Regional Carbon Sequestration Partnerships. These results 
were recently published in the ``Carbon Sequestration Atlas of the 
United States and Canada'' that is available on our website at http://
www.netl.doe.gov/publications/carbon-seq/refshelf.html.
    The two greatest challenges facing technology development for clean 
power production integrated with CCS are reducing the cost of carbon 
capture and proving the safety and efficiency of long-term geologic 
storage of CO2. DOE supports a robust RD&D program 
specifically designed to address these challenges. The Office of Fossil 
Energy's core Coal Technology Program includes the development of 
advanced technologies for pre-combustion (or gasification), post-
combustion, and oxy-combustion--multiple pathways to produce power and 
capture CO2--as well as a robust program for carbon 
sequestration to prove the viability of long-term geologic and 
terrestrial storage. DOE's Office of Science also supports basic 
research in areas such as combustion chemistry, fundamentally new 
materials, and modeling of combustion reactions that underpin the 
development of potential future clean coal technologies, and basic 
research towards improving our scientific understanding of the behavior 
of CO2 at potential geological sites.
    The 2012 goal of the Coal Technology Program is to show that we can 
develop advanced technology to capture and store at least 90 percent of 
the potential CO2 emissions from coal-fired power plants, 
with less than a 10 percent increase in the cost of electricity. This 
is an ambitious and significant goal, considering that commercially 
available technology to do this today will add from 30 to 70 percent to 
the cost of electricity.
    Based on the Energy Information Administration's 2007 new capacity 
forecast, 145 gigawatts of new coal-based capacity will be required in 
the United States by 2030, while still maintaining most of the 300 
gigawatts of generating capacity in the existing coal fleet. We have a 
fast-approaching opportunity to introduce a ``new breed'' of power 
plant--one that is highly efficient, capable of producing multiple 
products, and is virtually pollution-free (``near-zero'' emissions, 
including carbon). In addition to technology for new plants, we are 
also likely to need technology that will permit efficient, cost-
effective capture of CO2 emissions from the existing fleet. 
DOE's R&D program is aimed at providing the scientific and 
technological foundation for carbon capture and storage for both new 
and existing coal-fueled power plants.
    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, which 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. We are 
developing advanced gasification technology 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-emission'' coal-based energy.
    The portfolio of gasification projects that we are developing in 
partnership with industry covers a broad range of approaches. I'd like 
to highlight some of the important recent developments.
    The Power Systems Development Facility (PSDF) in Wilsonville, 
Alabama, operated by the Southern Company for DOE, provides a pilot-
scale test platform for evaluating components critical to the evolution 
of gasification technology. The ``transport gasifier'' under 
development at the PSDF is proving to be very promising in terms of 
efficiency and cost, especially for gasifying low-rank, high-moisture 
western coals. Data from this facility is providing the design basis 
for scaling technology components to full-size in support of near-zero-
emission coal systems.
    The Stamet dry-feed coal pump is another promising gasification 
sub-system that we have been sponsoring. It allows coal to be 
``pumped'' directly into a high-pressure gasifier, thus avoiding the 
need for coal drying and a complex and costly lock hopper feeding 
system--or, alternatively, a slurry feeding system that is inefficient 
when used to feed high-moisture western coals. We have tested the 
system successfully at the PSDF, and in recent tests at Stamet's 
facilities in California where operation was successfully demonstrated 
at conditions typical of high-pressure gasifiers.
    Another major program objective is the development of ion transport 
membrane (ITM) technology, an alternative to conventional cryogenic 
methods for oxygen production that promises capital cost reductions of 
$130 per kilowatt, and efficiency improvements of about one percent 
when integrated into oxygen-based gasification systems. This year we 
will test the robustness of the membranes under various process 
conditions and upsets in a five-ton-per-day unit that is operating at 
Air Products and Chemicals, Inc.'s, Sparrows Point industrial gas 
facility located near Baltimore, Maryland. The information generated 
from this small unit will be used to design and test a 150-ton-per-day 
facility that will pave the way for a full-scale commercial unit in the 
Department's FutureGen Project, discussed further below.
    Finally, we have been successfully testing the Research Triangle 
Institute's (RTI's) warm gas sulfur cleanup system at Eastman 
Chemical's Kingsport, Tennessee, chemical complex where a small syngas 
slipstream is taken from commercial coal gasifiers and processed in a 
transport desulfurization unit. Since last fall--in over 2,000 hours of 
operation--the unit has performed exceptionally well, achieving 
extremely low sulfur levels compared to existing commercial 
technologies. This new technology offers potential for capital cost 
reductions of $250 per kilowatt and efficiency improvements of three to 
four percent. We are currently in negotiations with RTI to scale up 
this technology for testing at a commercial Integrated Gasification 
Combined Cycle (IGCC) facility.
    The Advanced Turbine Program is leveraging the knowledge gained 
from previous turbine R&D activities to make unprecedented gains in 
state-of-the-art turbine designs. Potential pathways to advanced 
turbine designs for high-hydrogen fuels include increasing turbine 
inlet temperatures, developing advanced combustor designs, increasing 
compression ratios, and integrating air separation and CO2 
compression.
    For near-zero-emission power plants, a new generation of turbine 
technology is needed that is capable of operating on hydrogen fuels, 
without compromising operational performance, while achieving ultra-low 
NOX emissions.
    A primary goal of the Advanced Turbines Program is to show by 2012 
that we can operate on hydrogen fuel, increase efficiency by two to 
three percentage points over baseline, and reduce NOX emissions to two 
parts per million (ppm). At the same time, we hope to reduce capital 
cost when compared to today's turbines in existing IGCC plants. We are 
working with two of the turbine original equipment manufacturers, 
General Electric and Siemens Westinghouse, to meet these goals.
    To facilitate the development of near-zero-emission coal-based 
power systems, the Advanced Turbines Program is also funding R&D on 
oxygen-fired (oxy-fuel) turbines and combustors that provide high 
efficiency through the use of ultra-high-temperature power cycles. 
Bringing such oxy-fuel combustors and turbines to commercial viability 
will require development and integrated testing of the combustor, 
turbine components, advanced cooling technology, and materials.
    To reduce the costs associated with sequestering CO2, 
the Advanced Turbines Program is investigating novel approaches for 
CO2 compression, including development of the Ramgen shock-
wave compression technology. Successful development will reduce the 
substantial power requirements and costs associated with compression 
for any zero-emission approach.
    The Office of Fossil Energy has been developing high-temperature 
Solid Oxide Fuel Cells for a variety of applications under the Solid 
State Energy Conversion Alliance (SECA) program. These high-temperature 
fuel cells offer several significant advantages to coal-based near-
zero-emission power systems. Recognizing the strategic importance of 
being able to operate on domestic fuel resources, namely, coal, we are 
refocusing the program to coal-based power generation applications.
    First, electrochemical power generation is highly efficient and can 
result in large savings by reducing the size and cost of the up-front 
gasification and clean-up parts of the plant, as well as by reducing 
the amount of CO2 that has to be sequestered.
    Second, solid oxide technology can directly utilize carbon monoxide 
and methane produced in gasification without the need to shift the 
composition of the syngas to pure hydrogen, which incurs cost and 
efficiency penalties.
    Third, solid oxide fuel cells have built-in carbon separation 
capability if the anode (fuel side) and cathode (oxidant side) streams 
are not mixed. We expect that fuel cells will provide over a 10 
percentage point increase in efficiency in near-zero-emission systems, 
with capital costs comparable to or lower than current gas turbine/
steam turbine systems.
    DOE's Carbon Sequestration Program leverages basic and applied 
research with field verification to assess the technical and economic 
viability of CCS as a greenhouse gas mitigation option. The Program 
encompasses two main elements: Core R&D and Validation and Deployment. 
The Core R&D element focuses on technology solutions, including low-
cost, low-energy intensive capture technologies, that can be validated 
and deployed in the field. Lessons learned from field tests are fed 
back to the Core R&D element to guide future R&D.
    The key challenges the program is addressing are to demonstrate the 
ability to store CO2 in underground geologic formations with 
long-term stability (permanence), to develop the ability to monitor and 
verify the fate of CO2, and to gain public and regulatory 
acceptance. DOE's seven Regional Carbon Sequestration Partnerships are 
engaged in an effort to develop and validate CCS technology in 
different geologies across the Nation.
    Collectively, the seven Partnerships represent regions encompassing 
97 percent of coal-fired CO2 emissions, 97 percent of 
industrial CO2 emissions, 97 percent of the total land mass, 
and essentially all of the geologic storage sites in the United States 
potentially available for sequestration. The Partnerships are 
evaluating numerous CCS approaches to assess which approaches are best 
suited for specific geologies, and are developing the framework needed 
to validate and potentially deploy the most promising technologies.
    The Regional Partnership initiative is using a three-phased 
approach.
    Characterization, the first phase, was initiated in 2003 and 
focused on characterizing regional opportunities for CCS, and 
identifying regional CO2 sources and storage formations. The 
Characterization Phase was completed in 2005 and led to the current 
Validation Phase.
    Validation, the second phase, focuses on field tests to validate 
the efficacy of CCS technologies in a variety of geologic storage sites 
throughout the United States. Using the extensive data and information 
gathered during the Characterization Phase, the seven Partnerships 
identified the most promising opportunities for storage in their 
regions and are performing widespread, multiple geologic field tests. 
In addition, the Partnerships are verifying regional CO2 
storage capacities, satisfying project permitting requirements, and 
conducting public outreach and education activities.
    Deployment, the third phase, involves large-volume injection tests. 
This phase was initiated this fiscal year and will demonstrate CO2 
injection and storage at a scale necessary to demonstrate potential 
future commercial deployment. The geologic structures to be tested 
during these large-volume storage tests will serve as potential 
candidate sites for the future deployment of technologies demonstrated 
in the FutureGen Project as well as the Clean Coal Power Initiative 
(CCPI). The Department expects to issue a CCPI solicitation for carbon 
capture technologies at commercial scale in 2007.
    DOE also recognizes the importance of the existing fleet of coal-
fired power plants in meeting energy demand and possible future carbon 
constraints. Research is being pursued to develop technologies that 
dramatically lower the cost of capturing CO2 from power 
plant stack emissions. This research, supported by the Office of Fossil 
Energy, is exploring a wide range of approaches that includes 
membranes, ionic liquids, metal organic frameworks, improved CO2 
sorbents, advanced combustor concepts, advanced scrubbing, and oxy-
combustion. Additionally, advanced research is being pursued on high-
temperature materials, advanced sensors & controls, and advanced 
visualization software. These developments could provide significant 
efficiency improvements and cost reductions for both existing and 
future power plants, based on pulverized coal combustion.
    The FutureGen Project is an industry/government partnership to 
design, build, and operate a gasification-based, nearly emission-free, 
coal-fired electricity production plant. The 275-megawatt plant will be 
the cleanest fossil-fuel-fired power plant in the world. With respect 
to sequestration technologies, FutureGen will test, and ideally 
demonstrate the large-scale, permanent sequestration of the captured 
CO2 in a deep saline formation. FutureGen is scheduled to 
operate from 2012 to 2016, followed by a CO2 monitoring 
phase. The data and experience derived from this important endeavor 
will then be available to facilitate the design of the next generation 
of near-zero-emission plants.
    By working in partnership with other federal agencies, utilities, 
coal companies, research organizations, academia, and non-government 
organizations, we hope to make near-zero-emission coal technology a 
cost-effective and safe option to help meet our future power needs.
    Mr. Chairman, and Members of the Committee, this completes my 
statement. I would be happy to take any questions you may have at this 
time.

                      Biography for Carl O. Bauer
    Carl Bauer is Director of the National Energy Technology Laboratory 
(NETL), a national laboratory owned and operated by the U.S. Department 
of Energy (DOE). In this position, he oversees the implementation of 
major science and technology development programs to resolve the 
environmental, supply, and reliability constraints of producing and 
using fossil resources. This includes technologies for--

          Advanced coal-fueled power generation and hydrogen 
        production.

          Carbon sequestration.

          Environmental control for the existing fleet of 
        fossil steam plants.

          Improving the efficiency and environmental quality of 
        domestic oil and natural gas exploration, production, and 
        processing.

    Mr. Bauer served as NETL's Deputy Director from October 2003 until 
his current appointment in February 2005. In his previous position, Mr. 
Bauer was responsible for NETL's energy assurance and infrastructure 
protection activities, and he provided oversight for the Office of 
Institutional and Business Operations; the Office of Science, 
Technology, and Analysis; and the Office of Technology Impacts and 
International Coordination.
    Prior to serving as Deputy Director, Mr. Bauer was the Director of 
NETL's Office of Coal and Environmental Systems, with responsibility 
for all of NETL's activities related to coal and environmental 
research. Prior to that, he was Director of NETL's Office of Product 
Management for Environmental Management, with responsibility for 
development and demonstration of hazardous- and radioactive-waste 
cleanup technologies.
    Mr. Bauer has more than 30 years of experience in technical and 
business management in both the public and private sectors. His 
positions at the Department of Energy Headquarters have included 
Director of the Division of Work for Other Agencies, Director of the 
Idaho and Chicago Environmental Restoration Operations Division, Acting 
Director for the Environmental Management Office of Acquisition 
Management, and Director of the Office of Technology Systems. He has 
also served as Director of Engineering Support and Logistics, Naval Sea 
Systems Command for the U.S. Department of Defense; Vice President and 
General Manager of Technology Application, Inc.; and Vice President, 
Ship Systems and Logistics Group, Atlantic Research Corporation.
    Mr. Bauer received an M.S. in nuclear power engineering from the 
Naval Nuclear Power Postgraduate Program in 1972 and a B.S. in marine 
engineering/oceanography from the U.S. Naval Academy in 1971. He has 
taken additional postgraduate courses at the Wharton School of Business 
and George Washington University in business administration, finance, 
and management, and has received additional executive management 
training at Harvard University's John F. Kennedy School of Government.

    Chairman Lampson. Thank you, Mr. Bauer. We will postpone 
those questions for just a few minutes. Dr. Finley.

 STATEMENT OF DR. ROBERT J. FINLEY, DIRECTOR, ENERGY AND EARTH 
       RESOURCES CENTER, ILLINOIS STATE GEOLOGICAL SURVEY

    Dr. Finley. Thank you, Mr. Chairman and Members of the 
Committee.
    Understanding the capacity to geologically sequester carbon 
dioxide as a byproduct of fossil fuel use, including the use of 
advanced coal technologies, is an essential strategy to 
mitigate the growing potential for climate change related to 
CO2 buildup in the atmosphere.
    At the Illinois State Geological Survey, we have been 
investigating this capacity for more than five years, and since 
October of 2003, have been doing so as part of a competitively 
awarded U.S. Department of Energy Regional Carbon Sequestration 
Partnership. This partnership covers the Illinois Basin, a 
geological feature that covers most of Illinois, Southwestern 
Indiana, and Western Kentucky.
    Our Phase I effort focused on compiling and evaluating 
existing data, and resulted in a 496-page report, indicating 
that one, suitable CO2 sequestration reservoirs are 
present in the Illinois Basin, and that sufficient 
sequestration capacity existed to warrant further 
investigation. We then entered a Phase II validation effort, in 
which we are currently engaged, in which six small-scale field 
pilot projects will be carried out through September 2009.
    In July 2006, DOE managers of the Regional Carbon 
Sequestration Partnership began the process of developing a 
Carbon Sequestration Atlas of the United States and Canada. 
This Atlas was released in digital form in March of this year, 
and the first edition of the printed version was released last 
week at the DOE Annual Carbon Capture and Sequestration 
Conference. I have a copy of it here that Members may peruse at 
their leisure. I would be pleased to leave it with you.
    The Atlas suggests that there are some 3,500 billion tons 
of storage capacity in the regions covered by the partnerships. 
In my judgment, there is sufficient geological carbon 
sequestration capacity in the United States for geological 
sequestration to be one of multiple tools used on a large scale 
to reduce CO2 emissions from fixed sources, such as 
coal gasification facilities.
    While compiling our Phase I report, and while setting up 
environmental monitoring programs are integral to each of the 
six field pilots, we have been aware of the need to understand 
the risks, both short-term and long-term, of geological carbon 
sequestration. We have been paying as much attention to the 
overlying rock that will hold the carbon dioxide in place, the 
caprock or the seals, as we have to the rock into which the 
CO2 itself will be injected.
    To be an effective climate change mitigation strategy, the 
CO2 must remain in place and not leak back to the 
atmosphere, not contaminate potable groundwater, not affect 
surface biota, and not present a risk to human health and 
safety. We know that rock formations can perform this in an 
effective manner, as both reservoirs and seals, because they 
have trapped and held oil and natural gas that we drill for and 
produce every day. These hydrocarbons have been trapped in 
place for millions to hundreds of millions of years before 
being brought to the surface through wells. To minimize the 
risk of CO2 injection, the reverse of the process of 
oil and natural gas production, we need to apply many of these 
same advanced methods that we use to find oil and natural gas. 
We need to evaluate subsurface rock formations to find thick 
and competent reservoir seals, to avoid areas where faults and 
fractures could become leakage pathways, and to understand the 
chemical changes in the pore space of the rock where the 
CO2 will be injected.
    With respect to the safety of established projects, we have 
been injecting CO2 for enhanced oil recovery in 
reservoirs in West Texas for more than two decades. Since 1983, 
more than 600 million tons of pressurized CO2 have 
been injected into the surface, and 30 million tons are being 
injected currently on an annual basis. The safety record of 
this process has been excellent, with not a single loss of life 
incident during the period of injection. The injection of one 
million tons per year of CO2 for sequestration 
beneath the seabed of the North Sea has been taking place since 
1996, and based on published reports, this process has been 
both safe and effective.
    I would conclude from this experience with CO2, 
and from industry experience with geological storage of natural 
gas, that we could readily proceed with large-scale, by which I 
mean one million tons per year tests of geological 
sequestration for further evaluation of reservoirs and caprocks 
as they vary geologically around the country.
    To establish public confidence, all the regional 
partnerships have been carrying out outreach and education 
activities, and have been integrating environmental monitoring 
into our small-scale CO2 pilot tests. As we move to 
the upcoming larger scale tests, we need to invest even more 
into education, outreach, and especially environmental 
monitoring to ensure public confidence. Our experience to date, 
very much informed by the public meetings that we have held in 
regard to the two FutureGen finalist sites, which we are 
fortunate to have in the State of Illinois, has been the 
process of ensuring openness and transparency to help gain the 
public trust. Yes, we are putting something new into the 
subsurface. Yes, there are small and difficult to quantify 
risks, such as slow leakage, involved in carrying out any such 
effort, but yes, we are working diligently and in the most open 
way possible to investigate the geology of sequestration, and I 
believe that the geologic framework has the capacity and the 
security that we require to make sequestration a viable carbon 
management strategy.
    Thank you.
    [The prepared statement of Dr. Finley follows:]
                 Prepared Statement of Robert J. Finley
    Understanding the capacity to geologically sequester carbon dioxide 
(CO2) as a byproduct of fossil fuel use, including the use 
of advanced coal technologies, is an essential strategy to mitigate the 
growing potential for climate change related to carbon dioxide buildup 
in the atmosphere. At the Illinois State Geological Survey, we have 
been investigating this capacity for more than five years, and, since 
October of 2003, have been doing so as part of a U.S. Department of 
Energy (DOE) Regional Carbon Sequestration Partnership. This 
Partnership covers the Illinois Basin, a geological feature that 
extends across most of Illinois, southwestern Indiana, and western 
Kentucky. Our sister geological surveys in Indiana and Kentucky are our 
partners in this research. Our Phase I effort focused on compiling and 
evaluating existing data and resulted in a 496-page report in December 
2005 indicating 1) that suitable CO2 sequestration 
reservoirs were present in the Illinois Basin, and that 2) sufficient 
sequestration capacity existed warranting further investigation. We 
then entered a Phase II validation effort, in which we are currently 
engaged, in which six small-scale, field pilot injection projects will 
be carried out through September 2009. The injection phase of one field 
pilot has been completed and two more will see either injection or 
drilling of new wells for injection within the next 90 days. While 
planning and executing these field pilot projects, we have also been 
making further detailed assessments of geological storage capacity, as 
have the other six partnerships.
    In July 2006, DOE managers for the Regional Carbon Sequestration 
Partnerships convened a meeting at the Kansas Geological Survey to 
begin the process of developing a Carbon Sequestration Atlas of the 
United States and Canada. This Atlas was released in digital form in 
March 2007 and the first edition of the printed version was released 
last week in Pittsburgh at DOE's annual carbon capture and 
sequestration conference. The Atlas was developed on the basis of 
regional partnership work that began in 2003, and earlier, to 
understand the major geological reservoirs that may be utilized for 
carbon sequestration. This Atlas also builds on the work supported by 
DOE in the form of the original MIDCARB, and now NATCARB, digital 
databases that are accessible on the Internet. The Atlas documented 
some 3,500 billion tons of storage capacity in the regions covered by 
the Partnerships. In my judgment there is sufficient geological carbon 
sequestration capacity in the United States for geological 
sequestration to be one of multiple tools useful on a large scale to 
reduce CO2 emissions from fixed sources such as coal 
gasification facilities. In the Illinois Basin region, if we could 
capture 80 percent of all current fixed-source emissions, a volume of 
237 million tons of CO2 per year, we would have storage 
capacity for 122 to 485 years of emissions just in the deep saline 
reservoirs.
    While compiling our Phase I report, and while setting up 
environmental monitoring programs integral to each of our six field 
pilot projects, we have been aware of the need to understand the risks, 
both short- and long-term, of geological carbon sequestration. We have 
been paying as much attention to the overlying rock that will hold the 
carbon dioxide in place, the reservoir seal or caprock, as we have to 
the qualities of the reservoir rock that the CO2 will be 
injected into. To be an effective climate change mitigation strategy, 
the CO2 must remain in place and not leak back to the 
atmosphere, not contaminate potable ground water, not affect surface 
biota, and not present a risk to human health and safety. That implies 
that we must do an excellent job of investigating the properties of 
these rocks and the fluids now within them and predicting their 
performance in the future. We know that rock formations can perform as 
effective reservoirs and seals because they have trapped and held the 
oil and natural gas that we drill for and produce every day. These 
hydrocarbons have been trapped in place for millions to hundreds of 
millions of years before being brought to the surface through wells. To 
minimize the risk in CO2 injection, the reverse of the oil 
or natural gas production process, we need to apply many of the same 
advanced methods as we use to find oil and natural gas. We need to 
evaluate subsurface rock formations to find thick and competent 
reservoir seals, to avoid areas where faults and fractures could become 
leakage pathways, and to understand the chemical changes in the pore 
space of the rock that the CO2 will be injected into. All of 
this can be done to mitigate risk and if done well, and in sufficient 
detail, will allow appropriate sites with minimum risk to be selected 
for geological sequestration. After all, we also have decades of 
experience with underground natural gas storage projects at sites where 
tens of billions of cubic feet of flammable natural gas are stored 
safely and effectively.
    With respect to the safety of established projects, we have been 
injecting CO2 for enhanced oil recovery in West Texas for 
more than two decades. Since 1983, more than 600 million tons of 
pressurized CO2 have been injected and 30 million tons are 
currently being injected annually in West Texas oil reservoirs. The 
safety record of this process has been excellent with not a single 
incident of loss of life. The injection of CO2 for 
sequestration beneath the seabed of the North Sea has been taking place 
since 1996, and based on published reports, the CO2 has been 
readily tracked in the subsurface using geophysical techniques and the 
process has been safe and effective. About one million metric tonnes 
per year are being injected at a sub-seabed depth of 3,300 feet under a 
caprock about 260 feet thick, comparable to shale caprocks in the 
Illinois Basin. I would conclude from this experience with 
CO2, and from industry experience with geological storage of 
natural gas, that we should proceed with large-scale (one million tons/
year to one million tons over three to four years) tests of geological 
carbon sequestration for further evaluation of reservoirs and caprocks 
as they vary in different regions of the country. These projects need 
to be well funded and designed to build on the technical experience I 
have just described.
    To establish public confidence, all the regional partnerships have 
been carrying out public outreach activities and have been integrating 
environmental monitoring into their small-scale field testing of 
CO2 injection during Phase II. For our Illinois Basin 
region, this monitoring has been the largest single budget item in our 
Phase II project, and appropriately so. As we move to the upcoming 
larger-scale tests, we need to invest even more into education, 
outreach, and, especially, environmental monitoring to ensure public 
confidence. Our experience to date, very much informed by the public 
meetings we have held with regard to the two FutureGen finalist sites 
in Illinois, has been that openness and transparency are essential to 
the process of gaining public trust. Yes, we are putting something new 
into the subsurface. Yes, there are small and difficult-to-quantify 
risks, such as slow leakage, involved in carrying out any such effort. 
But, yes, we are working diligently and in the most open way possible 
to investigate the geology of sequestration, and I believe that the 
geologic framework has the capacity and the security that we require to 
make sequestration a viable carbon management strategy. I also believe, 
however, that some budget figures that I have seen for FY08 and FY09 
are inadequate to fully execute and monitor these critical large-scale 
tests in diverse geological settings around the U.S. I trust that this 
subcommittee and the Full Committee on Science and Technology will have 
the opportunity to review those allocations and give priority to the 
Phase III Regional Partnership Program's large-scale testing, among 
other important sequestration programs that benefit from the 
investments made to date in technology and expertise by the Department 
of Energy.
    In summary, I would suggest to the Subcommittee that we are 
beginning to have a substantive understanding of the geological 
capacity for carbon sequestration, especially based on research over 
the last two to five years in the U.S. and internationally. Advanced 
coal technologies including coal gasification for electricity 
production, coal to synthetic natural gas, and coal to liquid fuels 
will depend on geological sequestration capacity to directly manage 
their CO2 emissions. The need for such management has been 
made all the more evident by the growing concern over climate change as 
embodied in the assessments released by the Intergovernmental Panel on 
Climate Change (IPCC) and other groups since February of this year. 
While we are advancing sequestration technology, we must also address 
issues of long-term liability for sequestration projects, legal access 
to subsurface pore space, and issues of who will bear the costs of 
sequestration and how those costs will be distributed. Some of these 
issues are beginning to be articulated, but it is unlikely that these 
issues, or the testing of advanced coal technologies combined with 
carbon sequestration, can be addressed without unprecedented public-
private collaboration. I urge this subcommittee to facilitate that 
process as we look forward to implementing advanced coal technologies 
incorporating geological carbon sequestration as a preferred and 
routine approach to coal utilization.

                     Biography for Robert J. Finley
    Robert J. Finley is the Director of the Energy and Earth Resources 
Center at the Illinois State Geological Survey, Champaign, Illinois. He 
joined the Illinois Survey in February 2000 after serving as Associate 
Director at the Bureau of Economic Geology, The University of Texas at 
Austin. Rob's area of specialization is fossil energy resources. His 
work has ranged from large-scale resource assessment, addressing 
hydrocarbon resources at national and State scales, to evaluation of 
specific fields and reservoirs for coal, oil, and natural gas. He is 
currently heading a regional carbon sequestration partnership in the 
Illinois Basin aimed at addressing concerns with geological carbon 
management. Rob has served on committees of the National Petroleum 
Council, the American Association of Petroleum Geologists, the National 
Research Council, the Stanford Energy Modeling Forum, and the U.S. 
Potential Gas Committee. He has taught aspects of energy resource 
development since 1986 to numerous clients domestically and overseas in 
Venezuela, Brazil, South Africa, and Australia, among other countries. 
Rob holds a Ph.D. in geology from the University of South Carolina; he 
is currently also an Adjunct Professor in the Department of Geology, 
University of Illinois at Urbana-Champaign.

    Chairman Lampson. Thank you, Dr. Finley. Mr. Rencheck.

 STATEMENT OF MR. MICHAEL W. RENCHECK, SENIOR VICE PRESIDENT, 
  ENGINEERING, PROJECTS AND FIELD SERVICES, AMERICAN ELECTRIC 
                             POWER

    Mr. Rencheck. Good afternoon, Mr. Chairman and Members of 
the Committee. Thank you for inviting me to participate in this 
meeting.
    American Electric Power is one of the Nation's largest 
electricity utilities, with more than five million retail 
customers in 11 States. We are also one of the Nation's largest 
power generators, with more than 38,000 megawatts of generating 
capacity from a diverse fleet. In a particular note for today, 
AEP is one of the largest coal-fired electric generators in the 
U.S., and we have implemented a portfolio of voluntary actions 
to reduce, avoid, and offset greenhouse gases during the past 
decade.
    Coal generates over 50 percent of the electricity used in 
the United States, and is used extensively worldwide. As demand 
for electricity increases significantly, coal use will increase 
as well. In the future, coal-fired electric generation must be 
zero-emission or close to it. This will be achieved through new 
technologies that are being developed today, but are not yet 
proven or commercially available.
    Like most companies in our sector, AEP needs new 
generation. We are investing in new clean coal technology that 
will enable AEP and our industry to meet the challenge of 
reducing greenhouse gases for the long-term. This includes 
plans to build two new integrated gasification combined cycle 
units, IGCC, and two state-of-the-art ultrasupercritical units. 
These will be the first new generation of ultrasupercritical 
and IGCC units deployed in the United States. AEP is also 
taking a lead role of commercializing carbon capture technology 
for use on new generation, and more importantly, for use on 
existing generation as a retrofit.
    We signed a memorandum of understanding also for post-
combustion capture technology using Alstom's chilled ammonia 
system. Starting with a commercial performance verification 
project in mid to late 2008 in West Virginia, a project that 
will also include storage of the carbon dioxide in a saline 
aquifer, we will move to the first commercial sized project at 
one of our 450-megawatt plants at our Northeastern Unit in 
Oklahoma in 2011. This would capture about 1.5 million metric 
tons of CO2 per year, which will be used for 
enhanced oil recovery.
    We are also working with Babcock and Wilcox to develop its 
oxy-coal combustion technology, through development of a 30-
megawatt thermal pilot plant at its Barberton, Ohio facility in 
2007. Oxy-coal combustion forms a concentrated CO2 
post-combustion gas that can be stored without additional post-
combustion gas processing equipment. We are hoping to bring 
this technology from the drawing board to commercial scale 
early in the next decade.
    Retrofitting our existing fleet to ensure carbon capture 
will be neither easy nor inexpensive, and AEP is very 
comfortable leading the way. We have a long and impressive list 
of technological firsts that we achieved during our first 
hundred years of existence, but we have identified one very 
important caveat during our century of technological 
achievement and engineering excellence. Proving technology to 
be commercially viable and having that technology ready for 
widespread commercial use are two very different things. It 
takes time to develop off-the-shelf commercial offerings for 
new technology.
    AEP is not calling for an indefinite delay in the enactment 
of mandatory climate change legislation until the advanced 
technology, such as carbon capture and storage, is developed. 
However, as the requirements become more stringent during the 
next ten to twenty years, and we move beyond the availability 
of current technology to deliver those reductions, it is 
essential that requirements for deeper reductions allow 
sufficient time for the demonstration and commercialization of 
these advanced technologies.
    How can you help? It is also important to establish public 
funding, as well as incentives for private funding, for the 
development of commercially viable technology solutions, as 
well as providing the legal and the regulatory framework to 
facilitate this development. AEP believes that the IGCC and 
carbon capture and storage technologies need to be advanced, 
but the building of an IGCC and the timely development of 
commercially viable carbon capture and sequestration 
technologies will require additional public funding.
    AEP and others in our sectors have already invested heavily 
into research and early development of technologies that may 
eventually be commercially viable solutions to capture and 
store greenhouse gas emissions. For this reason, separate 
investment tax credits are needed to facilitate both the 
construction of IGCC plants now, and the development of CCS 
technologies for future use.
    American industry has long been staffed by excellent 
problem solvers. I am confident we will be able to develop the 
technologies to efficiently address emissions of greenhouse 
gases in an increasingly cost-effective manner. We have the 
brainpower. We need time, funding assistance, and the legal or 
regulatory support.
    Thank you.
    [The prepared statement of Mr. Rencheck follows:]
               Prepared Statement of Michael W. Rencheck

Summary of Testimony

    American Electric Power (AEP) is one of the Nation's largest 
electricity generators with over five million retail consumers in 11 
states. AEP has a diverse generating fleet--coal, nuclear, 
hydroelectric, gas, oil and wind. But of particular note, AEP is one of 
the largest coal-fired electricity generators in the U.S.
    Over the last 100 years, AEP has led the Industry in developing and 
deploying new technologies beginning with the first high voltage 
transmission lines at 345 kilovolt (kV) and 765 kV to new and more 
efficient coal power plants starting with the large central station 
power plant progressing to super-critical and ultra-super-critical 
power plants. During the past decade, American Electric Power has 
implemented a portfolio of voluntary actions to reduce, avoid or offset 
greenhouse gases (GHG). During 2003-05, AEP reduced its GHG emissions 
by 31 million metric tons of CO2 by planting trees, adding 
wind power, increasing power plant generating efficiency, and retiring 
less-efficient units among other measures.
    We also continue to invest in new clean coal technology that will 
enable AEP and our industry to meet the challenge of reducing GHG 
emissions for the long-term. This includes plans to build two new 
integrated gasification combined cycle (IGCC) plants and two state-of-
the-art, ultra-super-critical plants. These will be the first of the 
new generation of ultra-super-critical plants in the U.S. AEP plans to 
take a lead role in commercializing carbon capture technology. We 
signed a memorandum of understanding (MOU) with Alstom for post-
combustion carbon capture technology using its chilled ammonia system. 
Starting with a ``commercial performance verification'' project in mid 
to late 2008 in West Virginia, we would move to the first commercial-
sized project at one of our 450-megawatt coal-fired units at 
Northeastern Plant in Oklahoma by late 2011. This would capture about 
1.5 million metric tons of CO2 a year, which will be used 
for enhanced oil recovery. Additionally, we signed a memorandum of 
understanding with Babcock and Wilcox to participate in a oxy-coal 
pilot project. This project will be used to refine the process and 
eventually determine if the combustion technology can be retrofit into 
existing plants.
    Over all, AEP supports the adoption of an economy-wide cap-and-
trade type GHG reduction program that is well thought-out, achievable, 
and reasonable. We believe legislation can be crafted that does not 
impede AEP's ability to provide reliable, reasonably priced electricity 
to support the economic well-being of our customers, and includes 
mechanisms that foster international participation and avoids harming 
the U.S. economy. A pragmatic approach for phasing in GHG reductions 
through a cap-and-trade program coincident with developing technologies 
to support these reductions will be critical to crafting achievable and 
reasonable legislation.
    The development of these technologies will be facilitated by and 
are dependent on public funding through tax credits and similar 
incentives. AEP is doing its part as we aggressively explore the 
viability of this technology in several first-of-a-kind commercial 
projects. We are advancing the development of IGCC and other necessary 
technologies as we seek to build two IGCC plants and two state-of-the-
art ultra-super-critical power plants. 1n addition, we are a founding 
member of FutureGen, a ground-breaking public-private collaboration 
that aims squarely at making near-zero-emissions coal-based energy a 
reality. Simply put, however, commercially engineered and available 
technology to capture and store CO2 does not economically 
exist today and we strongly recommend that any legislation you adopt 
reflect this fact.

Testimony

    Good morning Mr. Chairman and distinguished Members of the House 
Committee on Science and Technology, Subcommittee on Energy and 
Environment.
    Thank you for inviting me here today. Thank you for this 
opportunity to offer the views of American Electric Power (AEP) and for 
soliciting the views of our industry and others on climate change 
technologies.
    My name is Mike Rencheck, Senior Vice President--Engineering, 
Projects & Field Services of American Electric Power (AEP). 
Headquartered in Columbus, Ohio, we are one of the Nation's largest 
electricity generators--with over 36,000 megawatts of generating 
capacity--and serve more than five million retail consumers in 11 
states in the Midwest and south central regions of our nation. AEP's 
generating fleet employs diverse sources of fuel--including coal, 
nuclear, hydroelectric, natural gas, and oil and wind power. But of 
particular importance for the Committee Members here today, AEP uses 
more coal than any other electricity generator in the Western 
hemisphere.

AEP's Technology Development

    Over the last 100 years, AEP has been an industry leader in 
developing and deploying new technologies beginning with the first high 
voltage transmission lines at 345 kilovolt (kV) and 765kV, to new and 
more efficient coal power plants starting with the large central 
station power plant, progressing to super-critical and ultra-super-
critical powers plants. We are continuing that today. We have 
implemented 14 selective catalytic reactors (SCRs), and 10 Flue Gas 
Desulphurization units, with others currently under construction, and 
we are a leader in developing and deploying mercury capture and 
monitoring technology. In addition, we continue to invest in new clean 
coal technology plants and R&D that will enable AEP and our industry to 
meet the challenge of significantly reducing GHG emissions in future 
years. For example, AEP is working to build two new generating plants 
using Integrated Gasification Combined Cycle (IGCC) technology in Ohio 
and West Virginia, as well as two highly efficient new generating 
plants using the most advanced (e.g., ultra-super-critical) pulverized 
coal combustion technology in Arkansas and Oklahoma. We are also 
providing a leading role in the FutureGen project, which once 
completed, will be the world's first near-zero CO2 emitting 
commercial scale coal-fueled power plant. We are also working to 
progress specific carbon capture and storage technology.

AEP's Major New Initiative to Reduce GHG Emissions

    In March, AEP announced several major new initiatives to reduce 
AEP's GHG emissions and to advance the commercial application of carbon 
capture and storage technology and Oxy-coal combustion. Our company has 
been advancing technology for the electric utility industry for more 
than 100 years. AEP's recent announcement continues to build upon this 
heritage. Technology development needs are often cited as an excuse for 
inaction. We see these needs as opportunities for action.
    AEP has signed a memorandum of understanding (MOU) with Alstom, a 
worldwide leader in equipment and services for power generation, for 
post-combustion carbon capture technology using Alstom's chilled 
ammonia system. It will be installed at our 1,300-megawatt Mountaineer 
Plant in New Haven, West Virginia as a ``30-megawatt (thermal) 
commercial performance verification'' project in mid to late 2008 and 
it will capture up to 100,000 metric tons of carbon dioxide 
(CO2) per year. Once the CO2 is captured, we will 
store it. The Mountaineer site has an existing deep saline aquifer 
injection well previously developed in conjunction with the Department 
of Energy (DOE) and Battelle. Working with Battelle and with continued 
DOE support, we will use this well (and develop others) to store and 
further study CO2 injection into deep geological formations.
    Following the completion of commercial verification at Mountaineer, 
AEP plans to install Alstom's system on one of the 450-megawatt coal-
fired units at its Northeastern Plant in Oologah, Oklahoma, as a first-
of-a-kind commercial demonstration. The system is expected to capture 
approximately 1.5 million metric tons of CO2 per year and be 
operational in late 2011. The CO2 captured at Northeastern 
Plant will be used for enhanced oil recovery.
    AEP has also signed an MOU with Babcock and Wilcox to pursue the 
development of Oxy-coal combustion that uses oxygen in lieu of air for 
combustion. The Oxy-coal combustion forms a concentrated CO2 
post combustion gas that can be stored without additional post 
combustion capture processes. AEP is working with B&W on a ``30-
megawatt (thermal) pilot project.'' The results are due in mid-2007 and 
then these results will be used to study the feasibility of a scaled up 
100-200MW (electric) demonstration. The CO2 from the 
demonstration project would be captured and stored in a deep saline 
geologic formation or used for enhanced oil recovery application.
    In March, AEP also voluntarily committed to achieve an additional 
five million tons of GHG reductions annually beginning in 2011. We will 
accomplish these reductions through a new AEP initiative that will add 
another 1,000MW of purchased wind power into our system, substantially 
increase our forestry investments (in addition to the 62 million trees 
we have planted to date), as well as invest in domestic offsets, such 
as methane capture from agriculture, mines, and landfills.
    AEP has also implemented efficiency improvements at several plants 
in its existing generation fleet. These improvements include new 
turbine blading, valve replacements, combustion tuning, and 
installation of variable speed drives on rotating equipment. Such 
improvements are currently reported through the Department of Energy's 
1605 (b) program to the extent they produce creditable reductions in 
greenhouse gas emissions. However, we are limited in the efficiency 
improvements we can make due to the ambiguities in the existing New 
Source Review program, and support further clarification and reform of 
this program to encourage efficiency improvements.

AEP Perspectives on a Federal GHG Reduction Program

    While AEP has done much, and will do much more, to mitigate GHG 
emissions from its existing sources, we also support the adoption of an 
economy-wide cap-and-trade type GHG reduction program that is well 
thought-out, achievable, and reasonable. Although today I intend to 
focus on the need for the development and deployment of commercially 
viable technologies to address climate change and not on the specific 
policy issues that must be addressed, AEP believes that legislation can 
be crafted that does not impede AEP's ability to provide reliable, 
reasonably priced electricity to support the economic well-being of our 
customers, and includes mechanisms that foster international 
participation and avoid creating inequities and competitive issues that 
would harm the U.S. economy. AEP supports reasonable legislation, and 
is not calling for an indefinite delay until advanced technology to 
support carbon capture and storage (CCS), among others, is developed. 
However, as the requirements become more stringent during the next ten 
to twenty years, and we move beyond the ability of current technology 
to deliver those reductions, it is essential that requirements for 
deeper reductions coincide with the commercialization of advanced 
technologies.

Phased-in Timing and Gradually Increasing Level of Reductions 
                    Consistent With Technology Development That Is 
                    Facilitated by Public Funding

    As a practical matter, implementing climate legislation is a 
complex undertaking that will require procedures for measuring, 
verifying, and accounting for GHG emissions, as well as for designing 
efficient administration and enforcement procedures applicable to all 
sectors of our economy. Only a pragmatic approach with achievable 
targets, supported by commercial technology, and reasonable 
timetables--that does not require too many reductions within too short 
a time period--will succeed.
    AEP also believes that the level of emissions reductions and timing 
of those reductions under a federal mandate must keep pace with 
developing technologies for reducing GHG emissions from new and 
existing sources. The technologies for effective carbon capture and 
storage from coal-fired facilities are developing, but are not 
commercially engineered to meet production needs, and cannot be 
artificially accelerated through unrealistic reduction mandates.
    While AEP and other companies have successfully lowered their 
average emissions and emission rates during this decade, further 
substantial reductions will require the wide-scale commercial 
availability of new clean coal technologies. AEP believes that the 
electric power industry can potentially manage much of the expected 
economic (and CO2 emissions) growth over the course of the 
next decade (2010-2020) through aggressively deploying renewable 
energy, achieving further gains in supply and demand-side energy 
efficiency, and implementing new emission offset projects. As stated 
above, AEP supports reasonable legislation, and is not calling for an 
indefinite delay of GHG reduction obligations until advanced clean coal 
technology is developed. However, as the reduction requirements become 
more stringent, and move beyond the ability of current technologies to 
deliver those reductions, it is important that those stringent 
requirements coincide with the commercialization of advanced 
technology. This includes the next generation of low- and zero-emitting 
technologies.
    Significantly, today's costs of new clean coal technologies with 
carbon capture and storage are much more expensive than current coal-
fired technologies. For example, carbon capture and storage using 
current inhibited monoethanolamine (MEA) technology is expected to 
increase the cost of electricity from a new coal fired power plant by 
about 60-70 percent. Even the newer chilled ammonia carbon capture 
technology we plan to deploy on a commercial sized scale by 2012 at one 
of our existing coal-fired units will result in significantly higher 
costs.
    Additionally the MEA technology has limitations under existing 
plant retrofit conditions. CO2 capture requires a large 
volume of steam to regenerate the amine used to capture the 
CO2. Review of several of our existing PC units indicates 
they can only supply enough steam from the power generation cycle to 
regenerate the amine necessary to capture about 50 percent of the 
CO2, without jeopardizing the steam cycle.
    It is only through the steady and judicious advancement of these 
applications during the course of the next decade that we can start to 
bring these costs down, in order to avoid substantial electricity rate 
shocks and undue harm to the U.S. economy.
    IGCC technology, for example, integrates two proven processes--coal 
gasification and combined cycle power generation--to convert coal into 
electricity more efficiently and cleanly than any existing uncontrolled 
power plant can. Not only is it cleaner and more efficient than today's 
installed power plants, but IGCC has the potential to be retrofitted in 
the future for carbon capture at a lower capital cost and with less of 
an energy penalty than traditional power plant technologies, but only 
after the technology has been developed and proven. Our IGCC plants 
will incorporate the space and layout for the addition of components to 
capture CO2 for sequestration.
    Our IGCC plants will be among the earliest, if not the first, 
deployments of large-scale IGCC technology. The cost of constructing 
these plants will be high, resulting in a cost of generated electricity 
that would be twenty to thirty percent greater than that from 
pulverized coal (PC) combustion technology. As more plants are built, 
the costs of construction are expected to come into line with the cost 
of PC plants.
    To help bridge the cost gap and move IGCC technology down the cost 
curve, there is a need for continuation and expansion of the advanced 
coal project tax credits that were introduced by the Energy Policy Act 
of 2005. All of the available tax credits for IGCC projects using 
bituminous coal were allocated to only two projects during the initial 
allocation round in 2006. More IGCC plants are needed to facilitate 
this technology. AEP believes an additional one billion dollars of 
section 48A (of the Internal Revenue Code) tax credits are needed, with 
the bulk of that dedicated to IGCC projects without regard to coal 
type.
    Along with an increase in the amount of the credits, changes are 
needed in the manner in which the credits are allocated. Advanced coal 
project credits should be allocated based on net generating capacity 
and not based upon the estimated gross nameplate generating capacity of 
projects. Allocation based upon gross, rather than net, generating 
capacity potentially rewards less efficient projects, which is 
antithetical to the purpose of advanced coal project tax incentives. 
AEP also believes that the Secretary of Energy should be delegated a 
significant role in the selection of IGCC projects that will receive 
tax credits.
    On a critical note, the inclusion of carbon capture and 
sequestration equipment must not be a prerequisite for the allocation 
of these additional tax credits due to the urgent need for new electric 
generating capacity in the U.S. AEP also believes that this requirement 
is premature and self-defeating to advancing IGCC technology. The 
addition would require yet-to-be developed technology and/or would 
cause the projected cost of a project to increase significantly, making 
it that much more difficult for a public utility commission to approve.
    AEP also believes that additional tax incentives are needed to spur 
the development and deployment of greenhouse gas capture and 
sequestration equipment for all types of coal fired generation. We 
suggest that additional tax credits be established to offset a 
significant portion of the incremental cost of capturing and 
sequestering CO2. These incentives could be structured 
partly as an investment tax credit, similar to that in section 48A (of 
the Internal Revenue Code), to cover the up-front capital cost, and 
partly as a production tax credit to cover the associated operating 
costs.
    In summary, AEP recommends a pragmatic approach for phasing in GHG 
reductions through a cap-and-trade program coincident with developing 
technologies to support these reductions.

Technology Is the Answer to Climate Change

    The primary human-induced cause of global warming is the emission 
of CO2 arising from the burring of fossil fuels. Put simply, 
our primary contribution to climate change is also what drives the 
global economic engine.
    Changing consumer behavior by buying efficient appliances and cars, 
by driving less, and other similar steps, is helping to reduce the 
growth of GHG emissions. However, these steps will never be enough to 
significantly reduce CO2 emissions from the burning of coal, 
oil and natural gas. Such incremental steps, while important, will 
never be sufficient to stabilize greenhouse gases concentrations in the 
atmosphere at a level that is believed to be capable of preventing 
dangerous human-induced interference with the climate system, as called 
for in the U.S.-approved U.N. Framework Convention on Climate Change 
(Rio agreement). For that, we need major technological advances to 
effectively capture and store CO2. The Congress and indeed 
all Americans must come to recognize the gigantic undertaking and 
significant sacrifices that this enterprise is likely to require.
    CCS should not be mandated until and unless it has been 
demonstrated to be effective and the costs have significantly dropped 
so that it becomes commercially engineered and available on a 
widespread basis. Until that threshold is met, it would be 
technologically unrealistic and economically unacceptable to require 
the widespread installation of carbon capture equipment. The use of 
deep saline geologic formations as primary long-term CO2 
storage locations has not yet been sufficiently demonstrated. There are 
no national standards for permitting such storage reservoirs; there are 
no widely accepted monitoring protocols; and the standards for 
liability are unknown (as well as whether federal or State laws would 
apply). In addition, who owns the rights to these deep geologic 
reservoirs remains a question.
    Outstanding technical questions for CO2 storage include: 
What is the number of injector wells needed? What is the injector well 
lifespan? What is the injector well proximity to other wells? What 
measurement, monitoring, and verification of storage in the geologic 
reservoirs is needed? What is the time span of post-injection 
monitoring? Much work needs to be done to ensure that the potential 
large and rapid scale-up in CCS deployment will be successful.
    Underscoring these realities, industrial insurance companies point 
to this lack of scientific data on CO2 storage as one reason 
they are disinclined to insure early projects. In a nutshell, the 
institutional infrastructure to support CO2 storage does not 
yet exist and will require time to develop. In addition, application of 
today's CO2 capture technology would significantly increase 
the cost of an IGCC or a new efficient pulverized coal plant, calling 
into serious question regulatory approval for the costs of such a plant 
by State regulators. Further, recent studies sponsored by the Electric 
Power Research Institute (EPRI) suggest that application of today's 
CO2 capture technology would increase the cost of 
electricity from an IGCC plant by 40 to 50 percent, and boost the cost 
of electricity from a conventional pulverized coal plant by 60 to 70 
percent, which would again jeopardize State regulatory approval for the 
costs of such plants.
    Despite these uncertainties, I believe that we must aggressively 
explore the viability of CCS technology in several first-of-a-kind 
commercial projects. AEP is committed to help lead the way, and to show 
how this can be done.
    As described earlier in this testimony, AEP will install carbon 
capture controls on two existing coal-fired power plants, the first 
commercial use of this technology, as part of our comprehensive 
strategy to reduce, avoid or offset GHG emissions.
    AEP is also building two state-of-the-art advanced ultra-super-
critical power plants in Oklahoma and Arkansas. These will be the first 
of the new generation of ultra-super-critical plants in the U.S. The 
more efficient turbine cycle on these ultra-super-critical units 
results from increased steam temperatures (greater than 1100 
+F). This improved efficiency reduces fuel (coal) 
consumption and thereby reduces emissions. The long-term goal for 
ultra-super-critical technology is to develop ``super alloys'' which 
can withstand operating temperatures of 1400 +F. This 
increased steam temperature will improve efficiency by about 20 percent 
relative to today's super-critical units that are operating in the 1000 
+F to 1050 +F range.
    AEP is also advancing the development of IGCC technology. IGCC 
represents a major breakthrough in our work to improve the 
environmental performance of coal-based electric power generation. AEP 
is in the process of permitting and designing two of the earliest 
commercial scale IGCC plants in the Nation. Construction of the IGCC 
plants will start once traditional rate recovery is approved.
    AEP is also a founding member of FutureGen, a ground-breaking 
public-private collaboration that aims squarely at making near-zero-
emissions coal-based energy a reality.
    FutureGen is a $1.5 billion, 10-year research and demonstration 
project. It is on track to create the world's first coal-fueled, near-
zero emission electricity and hydrogen plant with the capability to 
capture and sequester at least 90 percent of its carbon dioxide 
emissions.
    As an R&D plant, FutureGen will stretch--and indeed create--the 
technology envelope. Within the context of our fight to combat global 
climate change, FutureGen has a truly profound mission--to validate the 
cost and performance baselines of a fully integrated, near zero-
emission coal-fueled power plant.
    The design of the FutureGen plant is already underway, and we are 
making great progress. The plant will be on-line early in the next 
decade. By the latter part of that decade, following on the 
advancements demonstrated by AEP, FutureGen, and other projects, CCS 
technology should become a commercial reality.
    It is when these technologies are commercially demonstrated, and 
only then, that commercial orders will be placed on a widespread basis 
to implement CCS at coal-fueled power plants. That is, roughly around 
2020. Widespread deployment assumes that a host of other important 
issues have been resolved, and there is governmental and public 
acceptance of CCS as the proven and safe technology that we now believe 
it to be. AEP supports rapid action on climate change including the 
enactment of well thought-out and achievable legislation so that our 
nation can get started on dealing with climate change. However, the 
development of technology must coincide with any increase in the 
stringency of the program.
    A huge challenge that our society faces over the remainder of this 
century is how we will reduce the release of GHG emissions from fossil 
fuels. This will require nothing less than the complete re-engineering 
of the entire global energy system over the next century. The magnitude 
of this task is comparable to the industrial revolution, but for this 
revolution to be successful, it must stimulate new technologies and new 
behaviors in all major sectors of the world economy. The benefits of 
projects like FutureGen and the ones AEP is pursuing will apply to all 
countries blessed with an abundance of coal, not only the United 
States, but also nations like China and India.
    In the end, the only sure path to stabilizing GHG concentrations 
over the long-term is through the development and utilization of 
advanced technologies. And we must do more than simply call for it. Our 
nation must prepare, inspire, guide, and support our citizens and the 
very best and the brightest of our engineers and scientists; private 
industry must step up and start to construct the first commercial 
plants; and our country must devote adequate financial and 
technological resources to this enormous challenge. AEP is committed to 
being a part of this important process, and to helping you achieve the 
best outcome at the most reasonable cost and timelines possible. Thank 
you again for this opportunity to share these views with you.

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                   Biography for Michael W. Rencheck
    Michael W. Rencheck is Senior Vice President--Engineering, Projects 
and Field Services and is responsible for engineering, regional 
maintenance and shop service organizations, projects and construction, 
and new generation development.
    From June 2003 to December 2005, he was Senior Vice President--
Engineering, Technical and Environmental Services. He was also 
President of AEP Pro Serv from November 2002 to May 2003.
    He served as Senior Vice President--Engineering and Region 
Operations for Pro Serv from April to November 2002. Prior to that, he 
was Vice President--Strategic Business Improvement at AEP's D.C. Cook 
Nuclear Plant from October 2001 to March 2002 and Vice President--
Nuclear Engineering at Cook from 1998 to 2001.
    Previously, he served as Director--Nuclear Engineering and Projects 
at Florida Power Corp.'s Crystal River Nuclear Station in 1997-98. He 
was Director--System Engineering in 1997 and Manager--System 
Engineering from 1995 to 1997 at Public Service Electric & Gas Co. He 
held various technical and management positions at Duquesne light 
Company from 1983 to 1995.
    Rencheck has a Master's degree in management and computer 
information systems from Robert Morris College in Coraopolis, Pa., and 
a Bachelor's degree in electrical engineering from Ohio Northern 
University in Ada, Ohio. He is a professional engineer (Arkansas, 
Indiana, Kentucky, Michigan, Ohio, Pennsylvania, Virginia and West 
Virginia) and a certified senior reactor operator.

    Chairman Lampson. Thank you, Mr. Rencheck. Mr. Dalton.

   STATEMENT OF MR. STUART M. DALTON, DIRECTOR, GENERATION, 
               ELECTRIC POWER RESEARCH INSTITUTE

    Mr. Dalton. Thank you, Mr. Chairman, thank you to the 
Committee, and thank you for having EPRI here for the 
testimony. For those of you that don't know, EPRI is a 
nonprofit R&D organization, with operational headquarters in 
California, but with principal operations also in Tennessee and 
in North Carolina.
    I would like to summarize just a couple of brief points, 
and then elaborate briefly. Recent EPRI work shows that 
reduction of CO2 from the electricity sector will 
require a portfolio of technologies of all sorts, not just 
capture and storage. Efficiency improvements, which we haven't 
talked about much yet today, includes post-generation and can 
be implemented in both new and existing plants. CO2 
capture and storage, which we have talked about, will be an 
important CO2 reduction method, but there is no 
silver bullet technology, and it will not be easy or cheap.
    Accelerated R&D is needed in all types of coals and 
technologies, as well as for large-scale storage of CO2 
to prove effectiveness. And finally, policy and research needs 
to match this accelerated approach to efficiency enhancements, 
CO2 capture and storage.
    To expand on these briefly, recent analytical work by EPRI 
estimates that in order to significantly reduce CO2 
from the electricity sector, the U.S. will need to improve 
efficiency of electric transmission, and use efficiency, 
renewables, nuclear, as well as improvements in coal and 
capture and storage, a lot of it is to the subject of today's 
hearing.
    There is no single silver bullet, but there is a veritable 
arsenal of technology being developed worldwide that needs to 
be demonstrated and deployed. Multiple coal technologies with 
carbon capture and storage will need to be demonstrated across 
the range of U.S. applications. Our projects, and those of 
others, are that coal will continue to be used, and that we 
will need to optimize efficiency and CO2 capture and 
storage as a major part of the overall CO2 reduction 
program.
    Existing and new plants can improve efficiency, and reduce 
CO2 per megawatt-hour, per unit of power produced, 
by a variety of equipment and operational changes. Some of 
these can be accomplished through operational minor equipment 
changes. Some will require significant modifications in their 
equipment. All types of coal-based generation are capable of 
improving efficiency for new units. Significant programs are 
underway in the U.S. with regard to that. Over the next 20 
years, we believe the improvements can achieve CO2 
reductions of up to 20 percent per megawatt-hour without 
additional CO2 capture. The MIT Future of Coal 
report, the National Coal Council upcoming report, both lead to 
this same sort of measure.
    It will require a sustained R&D effort and substantial 
investment in demonstration facilities. One example, the DOE 
Energy Industries of Ohio, Oakridge National Lab, EPRI, as well 
as the equipment suppliers, have been working on next 
generation superalloys for some years, but there is no 
demonstration path going forward at this point toward an 
ultrasupercritical coal technology of the advanced type in the 
U.S., as there is in Europe.
    Technical barriers to reduce CO2 include cost 
and energy, use of capture, and the assurance of safe storage, 
as we have talked about. We believe CCS costs and barriers can 
be overcome through a joint public and private research 
development demonstration effort.
    We believe that they can be integrated into all types of 
new coal power plants, combined cycles, IGCCs, pulverized coal, 
fluidized bed combustion, oxyfuel, and that demonstrations are 
vital. In our opinion, no advanced coal technology is 
economically preferred for adopting CCS. When you add capture, 
it becomes a horse race, in our opinion.
    If you use today's technology to capture, compress, 
transport, and store, you may see a cost increase of pulverized 
coal plants of 60 to 80 percent, 40 to 50 percent for an IGCC 
plant, in our estimation. With an aggressive research and 
development demonstration program, these costs can be brought 
down. Sites for long-term storage are regionally available 
throughout the U.S., yet there are major challenges to 
overcome, as you have heard. Specifically, we believe large-
scale, greater than one million tons a year demonstrations, 
need to commence as soon as possible, and the legal and 
regulatory framework needs to be established for long-term 
ownership and liability.
    We believe there are gaps in the policy toward, to quickly 
pursue this research, but primarily, policy toward establishing 
long-term liability for CO2 storage when proper 
safeguards are in place. We believe there are pathways for 
this, and that industry and government need to act now to move 
this forward to improve efficiency, capture, and guiding 
principles for storage.
    Thank you very much.
    [The prepared statement of Mr. Dalton follows:]
                 Prepared Statement of Stuart M. Dalton
    Thank you, Mr. Chairman, Ranking Member Inglis, and Members of the 
Committee. I am Stuart Dalton, Director of Generation for the Electric 
Power Research Institute (EPRI), a non-profit, collaborative R&D 
organization. EPRI has principal locations in Palo Alto, California, 
Charlotte, North Carolina, and Knoxville, Tennessee. EPRI appreciates 
the opportunity to provide testimony to the Committee on the topic of 
``Prospects for Advanced Coal Technologies: Efficient Energy 
Production, Carbon Capture and Sequestration''
    I want to focus my comments today on three subjects: (I) the 
technological challenges our country faces in limiting carbon dioxide 
(CO2) emissions from power plants that use coal as an energy 
source through both efficiency gains and CO2 capture and 
sequestration (2) policy and research gaps where we believe the federal 
government can do more to facilitate the reduction of CO2 
emissions from coal, and (3) highlights from recent EPRI analytical 
work that emphasizes the importance of advanced coal technologies as 
part of an overall low-cost, low-carbon portfolio of options to reduce 
greenhouse gas emissions associated with climate change.

Background

    Coal is the energy source for over half of the electricity 
generated in the United States, and numerous forecasts of future energy 
use show that coal will continue to have a dominant share in our 
electric power generation for the foreseeable future. Coal is a stably 
priced, affordable, domestic fuel that can be used in an 
environmentally responsible manner. Over the past three decades, 
development and application of advanced pollution control technologies 
and sensible regulatory programs have reduced emissions of criteria air 
pollutants from new coal-fired power plants by more than 90 percent. 
And by displacing otherwise needed imports of natural gas or fuel oil, 
coal helps address America's energy security and reduces our trade 
deficit with respect to energy.
    By 2030, according to the Energy Information Administration, the 
consumption of electricity in the United States is expected to be 
approximately 40 percent higher than current levels. At the same time, 
to responsibly address the risks posed by potential climate change, we 
must substantially reduce the greenhouse gas emissions intensity of our 
economy in a way which allows for continued economic growth and 
maintains the benefits that energy provides. This is not a trivial 
matter--it implies a substantial change in the way we produce and 
consume electricity. Because coal contains a higher percentage of 
carbon than other fossil fuels such as natural gas, and because this 
carbon is emitted as CO2, coal presents a greater challenge 
to achieving reduced greenhouse gas emissions.
    Technologies to reduce CO2 emissions from coal will 
necessarily be one part of an economy-wide solution that includes 
greater end-use efficiency, increased renewable energy, more efficient 
use of natural gas, expanded nuclear power, and similar transformations 
in the transportation, commercial, industrial, and residential sectors 
of our economy. In fact, our work at EPRI on the impacts of climate 
policy on technology development and deployment has consistently shown 
that non-emitting technologies for electricity generation will likely 
be less expensive than technologies for limiting emissions of direct 
fossil fuel end uses in other sectors.
    EPRI stresses that no single advanced coal generating technology 
(or any generating technology) has clear-cut economic advantages across 
the range of U.S. applications. The best strategy for meeting future 
electricity needs while addressing climate change concerns and economic 
impact lies in developing multiple technologies from which power 
producers (and their regulators) can choose the option best suited to 
local conditions and preferences. Assuring timely, cost-effective coal 
power technology with CO2 capture entails simultaneous and 
substantial progress in research, development and demonstration (RD&D) 
efforts to improve capture processes and fundamental plant systems. 
EPRI sees the need for government and industry to pursue these and 
other pertinent RD&D efforts aggressively through significant public 
policy and funding support. Early commercial viability will likely come 
only through firm commitments to the necessary R&D and demonstrations 
and through collaborative arrangements that share risks and disseminate 
results.
    Improvements and new development in several technology areas are 
required to achieve large scale reduction of CO2 emissions 
from coal power plants. These needs can be described in three major 
aspects:

          Substantially increased thermodynamic efficiency of 
        coal plants

          Cost-effective, efficient, commercially available 
        technologies for capture of CO2 from coal plants

          Cost-effective, commercially available technologies 
        for storage of captured CO2

    Each of these areas presents substantial technology 
challenges requiring a sustained investment in RD&D.

Increasing Coal Plant Efficiency

    Although the United States was an early leader in developing high-
efficiency coal plant designs, we have built very few new coal power 
plants in the last two decades and are now playing catchup in the world 
race to achieve high-efficiency designs. In the 1950s and `60s, the 
United States was the world's pioneer in power plants using 
thermodynamically efficient ``super-critical'' and ``ultra-super-
critical'' steam conditions. Exelon's coal-fired Eddystone Unit 1, in 
service since 1960, still boasts the world's highest steam temperatures 
and pressures. Because of reliability problems with some of these early 
units, U.S. designers retreated from the highest super-critical steam 
conditions until recently when international efforts involving EPRI and 
U.S., European and Japanese researchers concentrated on new, reliable 
materials for high-efficiency pulverized coal plants. Given the 
prospect of potential CO2 regulations (and efforts by power 
producers to demonstrate voluntary CO2 reductions), the 
impetus for higher efficiency in future coal-based generation units has 
gained economic traction worldwide. In fact, the majority of new 
pulverized coal (PC) plants announced over the last two years will 
employ high-efficiency super-critical steam cycles, and several will 
use the ultra-super-critical steam (USC) conditions with very high 
temperature, high efficiency designs heretofore used only overseas 
(aside from Eddystone).
    EPRI is working with the Department of Energy, the Ohio Coal 
Development Office and major equipment suppliers on an important 
initiative to qualify a whole new class of nickel-based ``super-
alloys,'' which will enable maximum steam temperatures to rise from an 
ultra-super-critical steam temperature of 1100+F to an 
``advanced'' ultra-super-critical steam temperature of 
1400+F.
    Combined with a modest increase in steam pressure, this provides an 
efficiency gain that reduces a new plant's carbon intensity (expressed 
in terms of tons of CO2 emitted per megawatt-hour [Tons/
MWh]) by about 20 percent relative to today's state-of-the-art plants. 
Even modest increases in steam conditions can raise efficiency by 
several percent in the near-term (a two percent increase in efficiency, 
for example, represents a roughly five percent reduction of CO2 
production and coal use). If capture of the remaining CO2 is 
desired, improved efficiency will also reduce the required size of the 
capture equipment and the amount of coal mined and transported.
    However, realization of this opportunity will not be automatic. In 
fact, it will require a renewed, sustained R&D commitment and 
substantial investment in demonstration facilities to bring new 
technologies to market. The European Union has embraced such a strategy 
and is midway through its program to demonstrate a pulverized coal 
plant with 1300+F steam conditions, which was realistically 
planned as a 20-year activity. Efficiency improvements will also be 
important for other coal power technologies. The world's first super-
critical circulating fluidized-bed (CFB) plant is currently under 
construction in Poland. Many new units in China are being built with 
temperatures and efficiencies higher than recent U.S. units, as the 
cost of fuel and environmental pressures rise.
    The greatest increase in efficiency for integrated gasification 
combined cycle (IGCC) units will come from increases in the size and 
efficiency of the gas turbines and improvements in their ability to 
handle hydrogen rich ``syngas'' that would be produced in IGCC plants 
designed for CO2 capture.
    A number of technologies are being developed that promise to 
decrease the amount of CO2 per unit of power produced (e.g., 
pounds CO2/kWh or Tons/MWh). With today's technology, a 
modern pulverized coal plant and a modern coal-based IGCC plant would 
produce roughly the same amount of CO2/kWh. Neither achieves 
CO2 capture without significant operational and hardware 
modifications and some loss of efficiency. Both are expected to achieve 
efficiency advances and cost reductions based on research and 
development occurring worldwide. EPRI believes that both industry and 
the government should support the development, demonstration, and 
deployment of multiple high-efficiency technologies for the future, 
rather than picking technology winners.

CO2 Capture Technology

    Carbon dioxide capture and storage (CCS) technologies can be 
feasibly integrated into virtually all types of new coal-fired power 
plants, including IGCC, PC, CFB and variants such as oxy-fuel 
combustion. For those constructing new plants, it is unclear which type 
of plant would be economically preferred if it were built to include 
carbon capture. All can have relative competitive advantages under 
various scenarios.
    A utility's choice between these technologies will depend on 
available coals and their physical-chemical properties, desired plant 
size, the CO2 capture process and its degree of integration 
with other plant processes, plant elevation, the value of plant co-
products, and other factors. For example, IGCC with CO2 
capture generally shows an economic advantage with low-moisture 
bituminous coals. For coals with high moisture and low heating value, 
such as sub-bituminous and lignite coals, a recent EPRI study (report 
1014510 available publicly) shows PC with CO2 capture as 
competitive with IGCC with CO2 capture. However, no single 
set of costs can represent all conditions. In addition to such 
variables as coal type and plant design, the cost of electricity will 
also vary due to plant location and the type of financing of the 
facility receives.
Post-combustion CO2 Capture
    Although carbon dioxide capture appears technically feasible for 
all coal power technologies, it poses substantial engineering 
challenges (requiring major investments in R&D and demonstrations) and 
comes at considerable cost. However, analyses by EPRI and the Coal 
Utilization Research Council suggest that once these substantial 
investments are made, the cost of CCS becomes manageable and, 
ultimately, coal-based electricity with CCS can be cost competitive 
with other low-carbon generation technologies.
    Post-combustion CO2 separation processes (placed after 
the boiler in the power plant) are currently used commercially in the 
food and beverage and chemical industries, but these applications are 
at a scale much smaller than that needed for power producing PC or CFB 
power plants. These processes themselves are also huge energy 
consumers, and without investment in their improvement, they would 
reduce plant electrical output by as much as 30 percent creating the 
need for more new plants.
    EPRI's most recent cost estimates suggest that for PC plants, the 
addition of CO2 capture using amine solvents (the most 
highly developed technical option currently available), along with 
drying and compression, pipeline transportation to a nearby storage 
site, and underground injection, would add 60-80 percent to the net 
present value of life cycle costs of electricity (expressed as 
levelized cost-of-electricity, or COE, and excluding storage site 
monitoring, liability insurance, etc.). With coal providing 50 percent 
of U.S. electricity generation, this translates into a potentially 
significant increase in consumers' electric bills.
Oxy-firing
    For PC plants, the introduction of oxy-fuel or oxy-coal combustion 
may allow further reductions in CO2 capture costs by 
allowing the flue gas to be compressed directly, without any CO2 
separation process while also allowing the size of the super-critical 
steam generator to be reduced. Boiler suppliers and major European and 
Canadian power generators are actively working on pilot-scale testing 
and scale-up of this technology. AEP has recently announced plans to 
study use of this ``oxy-coal'' technology for retrofitting an existing 
plant, and SaskPower (Saskatchewan Power) has announced that, Babcock & 
Wilcox Canada (B&W) and Air Liquide will jointly develop the SaskPower 
Clean Coal Project.
Pre-combustion CO2 Capture
    CO2 separation processes suitable for IGCC plants are 
used commercially in the oil and gas and chemical industries at a scale 
closer to that ultimately needed, but their application necessitates 
deployment of modified IGCC plant equipment, including additional 
chemical process steps and gas turbines that can burn nearly pure 
hydrogen.
    The COE cost premium for including CO2 capture in IGCC 
plants, along with drying, compression, transportation and storage, is 
about 40-50 percent. Although this is a lower cost increase in 
percentage terms than that for PC plants, IGCC plants initially cost 
more than PC plants. Thus, the bottom-line cost to consumers for power 
from IGCC plants with capture may be comparable to that for PC plants 
with capture, depending on the types of coal used, elevation of the 
plant and other site-specific factors.
    It should be noted that IGCC plants (like PC plants) do not capture 
CO2 without substantial plant modifications, energy losses, 
and investments in additional process equipment. As noted above, 
however, the magnitude of these impacts could likely be reduced 
substantially through aggressive investments in R&D. Historical 
experience with the development of environmental control technologies 
for today's power plants suggests that technological advances from 
``learning-by-doing'' will likely lead to significant cost reductions 
in CO2 capture technologies as the installed base of plants 
with CO2 capture grows. An International Energy Agency study 
led by Carnegie Mellon University suggested that overall electricity 
costs from plants with CO2 capture could come down by 15 
percent relative to the currently predicted costs after about 200 
systems were installed.
    Furthermore, despite the substantial cost increases for adding 
CO2 capture to coal-based IGCC and PC power plants, their 
resulting cost-of-electricity is still usually less than that for 
natural gas-based plants at current and forecast natural gas prices.
    Engineering analyses by EPRI, DOE and the Coal Utilization Research 
Council suggest that costs could come down faster through CO2 
capture process innovations or, in the case of IGCC plants, fundamental 
plant improvements--provided sufficient RD&D investments are made. EPRI 
pathways for reduction in capital costs and improvements in efficiency 
are embodied in two companion RD&D Augmentation Plans developed under 
the collaborative CoalFleet for Tomorrow program. The IGCC plan (Report 
No. 1013219) is publicly available, and the PC plan will be available 
later this year. Efforts toward reducing the cost of IGCC plants with 
CO2 capture will focus on adapting more advanced and larger 
gas turbines for use with hydrogen-rich fuels, lower-cost oxygen 
supplies, improved gas clean-up, advanced steam cycle conditions and 
other activities.

CO2 Transportation and Geologic Storage

    Geologic sequestration of CO2 has been proven effective 
by nature, as evidenced by the numerous natural underground CO2 
reservoirs in Colorado, Utah and other western states. CO2 
is also found in natural gas reservoirs, where it has resided for 
millions of years. Thus, evidence suggests that depleting or depleted 
oil and gas reservoirs, and similar ``capped'' sandstone formations 
containing saltwater that cannot be made potable, are capable of 
storing CO2 for millennia or longer. Geologic sequestration 
as a strategy for reducing CO2 emissions is being 
demonstrated in numerous projects around the world.
    Three relatively large projects--the Sleipner Saline Aquifer 
CO2 Storage (SACS) project in the North Sea off of Norway; 
the Weyburn-Midale Project in Saskatchewan, Canada and the In Salah 
Project in Algeria--together sequester about three to four million 
metric tons of CO2 per year, which approaches the output of 
just one typical 500 megawatt coal-fired power plant. With 17 
collective years of operating experience, these projects suggest that 
CO2 storage in deep geologic formations can be carried out 
safely and reliably. Furthermore, CO2 injection technology 
and subsurface behavior modeling have been proven in the oil industry, 
where CO2 has been injected for 35 years for enhanced oil 
recovery (EOR) in the Permian Basin fields of west Texas and Oklahoma 
and in other U.S. fields. Regulatory oversight and community acceptance 
of injection operations are well established in those contexts.
    Within the United States, DOE manages an active R&D program, the 
Regional Carbon Sequestration Partnerships, that is mapping geologic 
formations suitable for CO2 storage and conducting pilot-
scale CO2 injection validation tests across the country. 
These tests, as well as most commercial applications for long-term 
storage, will compress CO2 to a liquid-like ``super-
critical'' state to maximize the amount that can be stored. Virtually 
all CO2 storage will be at least a half-mile underground, 
where the CO2 will be injected into a porous sandstone-like 
material saturated with salty water. CO2 will be stored in 
locations with geologic seals to minimize the likelihood of any leakage 
to the atmosphere (which would defeat the purpose of sequestering the 
CO2 in the first place).
    DOE's Regional Carbon Sequestration Partnerships represent a broad 
collaboration of public agencies, private companies and non-profits; 
they would be an excellent vehicle for conducting larger ``near-
deployment scale'' CO2 injection tests to prove specific 
U.S. geologic formations, which EPRI believes to be one of the keys to 
commercializing CCS for coal-based power plants. Evaluations by these 
Regional Partnerships and others suggest that enough geologic storage 
capacity exists in the United States to hold several centuries' worth 
of CO2 emissions from coal-based power plants and other 
stationary sources. However, the distribution of suitable storage 
formations across the country is not uniform: some areas have ample 
storage capacity whereas others appear to have little or none.
    Thus, CO2 captured at some power plants would require 
pipeline transportation for several hundred miles to reach suitable 
injection locations, which may be in other states. While this adds 
cost, it does not represent a technical hurdle because CO2 
pipeline technology has been proven in oil field FOR applications. As 
CCS is applied commercially, EPRI expects that early projects would 
take place at coal-based power plants near to sequestration sites or to 
existing CO2 pipelines. As the number of projects increases, 
regional CO2 pipeline networks connecting multiple sources 
and storage sites would be needed.
    There is still much work to be done before CCS can implemented on a 
scale large enough to significantly reduce CO2 emissions 
into the atmosphere. In addition to large-scale demonstrations at U.S. 
geologic formations, many legal and institutional uncertainties need to 
be resolved. Uncertainty about long-term monitoring requirements, 
liability and insurance is an example. State-by-state variation in 
regulatory approaches is another. Some geologic formations suitable for 
CO2 storage underlie multiple states. For private companies 
considering CCS, these various uncertainties translate into increased 
risk.

The Promise of CCS

    Recent EPRI work has illustrated the urgent necessity to develop 
CCS technologies as part of the solution to satisfying our energy needs 
in an environmentally responsible manner. Our recently released 
``Electricity Technology in a Carbon-Constrained Future'' study 
suggests that with aggressive R&D, demonstration and deployment of 
advanced electricity technologies, it is technically feasible to slow 
down and stop the increase in U.S. electric sector CO2 
emissions, and to then eventually reduce them over the next 25 years 
while simultaneously meeting the increased demand for electricity. Of 
the technologies that can eventually lead to reductions in CO2 
emissions, the study indicates that the largest single contribution 
would come from applying CCS technologies to new coal-based power 
plants coming on-line after 2020.
    Many other U.S. and international climate models and reports have 
stressed that CCS is a vital part of the needed technology mix in any 
carbon-constrained future. We believe action is needed now to assure we 
can meet these technological and cost challenges.

R&D Gaps

    A gap in the policy and RD&D area that EPRI believes needs to be 
addressed by the U.S. industry and government is the funding of 
multiple capture, transport, and storage demonstrations at large scale 
(>1 million metric tons per year of CO2). These 
demonstrations should encompass a variety of coal technologies and 
capture processes, and should be conducted in multiple regions, using 
varying geologic formations. Monitoring will need to be conducted to 
assure long-term storage effectiveness.
    Engineering analyses by EPRI, DOE and the Coal Utilization Research 
Council suggest that costs could come down faster through CO2 
capture process innovations or, in the case of IGCC plants, fundamental 
plant improvements--provided sufficient RD&D investments are made. 
Combined with EPRI's past experience in transforming science into 
deployed technologies, these analyses clearly indicate that a sustained 
and substantial RD&D investment will be necessary to assure the 
availability of CCS and levels of coal plant performance compatible 
with potential CO2 policies.
    EPRI pathways for reduction in capital cost and improvement in 
efficiency for IGCC plants are embodied in an RD&D Augmentation Plan 
developed under the CoalFleet for Tomorrow program. This figure shows 
how efficiency can be increased over the next two decades as costs are 
decreased in constant dollar terms. The detailed plans for this have 
been developed in our collaborative efforts with firms form five 
continents and over 60 participants. A similar figure appears for 
combustion processes and shows equally impressive efficiency and cost 
gains. Neither of these can be realized without a strong commitment to 
research development and demonstration.

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    Efforts toward reducing the cost of IGCC plants with CO2 
capture will focus on adapting more advanced and larger gas turbines 
for use with hydrogen-rich fuels, lower-cost oxygen supplies, improved 
gas clean-up, advanced steam cycle conditions, and more.

[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


    For PC plants, the progression to advanced ultra-super-critical 
steam conditions will steadily increase plant efficiency and reduce 
CO2 production. Improved solvents are expected to greatly 
reduce post-combustion CO2 capture process. EPRI is working 
to accelerate the introduction of novel, alternative CO2 
separation solvents with much lower energy requirements for 
regeneration. Such solvents--for example, chilled ammonium carbonate--
could reduce the loss in power output imposed by the CO2 
capture process from about 30 percent to about 10 percent. At present, 
a small pilot plant (five MW-thermal) for chilled ammonia is being 
designed for installation at a power plant in Wisconsin later this 
year; success there would warrant a scale-up to a larger pilot or pre-
commercial plant. An EPRI timeline (compatible with DOE's timeframe) 
for the possible commercial introduction of post-combustion CO2 
capture follows.

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    The introduction of oxy-fuel combustion may allow further 
reductions in CO2 capture costs by allowing the flue gas to 
be compressed directly, without any CO2 separation process 
and reducing the size of the super-critical steam generator. Boiler 
suppliers and major European and Canadian power generators are actively 
working on pilot-scale testing and scale-up of this technology.
    Assuring timely, cost-effective coal power technology with CO2 
capture entails simultaneous and substantial progress in RD&D efforts 
on improving capture processes and fundamental plant systems. EPRI sees 
the need for government and industry to pursue these and other 
pertinent RD&D efforts aggressively through significant public policy 
and funding support. Early commercial viability will likely come only 
through firm commitments to the necessary R&D and demonstrations and 
through collaborative arrangements that share initial risks and 
disseminate results.
    The urgent need to establish an enhanced RD&D program for 
developing advanced coal and carbon capture and storage technologies is 
further increased by the likelihood that, as is typical for research, 
unexpected technical challenges will surface and require additional 
time, effort and funding to resolve.

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Policy Gaps

    Without incentives or regulatory requirements, or a market for 
CO2, CCS will not be chosen based on economics. In addition 
to incentives to encourage use of CCS, the State and Federal 
governments will need to deal with the issues of land use, ownership, 
and liability for CO2. This is perhaps the biggest unknown. 
No company can take on unlimited liability--options will be needed to 
allow firms to make long-term commitments to the technology. Such 
options may include special insurance provisions, State or federal 
liability provisions, and must include clarity in regulatory 
requirements for long-term storage of CO2. Models and 
current analogies lead us, and many in the industry, to believe that 
the risk should be manageable, but the unknowns of long-term liability 
makes this risk difficult to manage.

Conclusions

    Our country does face significant technology challenges in limiting 
CO2 emissions from coal and it will require multiple 
technological approaches for capture and multiple storage 
demonstrations to prove the cost, efficiency, and effectiveness of 
CO2 capture and storage. These must be pursued in the near 
future to provide options for CO2 capture and storage on 
timeframes compatible with potential policies.
    Our research indicates that with proper support and an RD&D program 
sustained over the coming decades, the technology for CCS can play a 
significant role in reducing CO2 emissions from the power 
industry to meet future national requirements.

Summary of Testimony

    Coal is a stably priced, affordable, domestic fuel that can be used 
in an environmentally responsible manner. It is the workhorse of the 
U.S. electricity grid, accounting for more than half of all the power 
generated. Forecasts of future U.S. energy needs envision the continued 
predominance of coal in the electric power sector. Thus, technologies 
to reduce CO2 emissions from coal-based power plants must be 
part of the set of solutions to climate change concerns. For the 
electric sector, that portfolio will also include improved efficiency 
in transmission and end use, increased renewable energy, more efficient 
use of natural gas, and expanded nuclear power. Analogous low-carbon 
transformations must occur in the economy's transportation, commercial, 
industrial, and residential sectors. Even within the sub-sector of 
coal-based electricity, EPRI stresses that a portfolio of advanced coal 
technologies is needed. No single technology has clear-cut economic 
advantages across the range of U.S. applications. The best strategy for 
reducing CO2 emissions lies in developing multiple 
technologies from which power producers (and their regulators) can 
choose the option best suited to local conditions and preferences.
    An often-cited step is improving the efficiency of new coal power 
plants. This can achieve CO2 reductions of up to 20 percent 
per megawatt hour of electricity before the addition of any dedicated 
CO2 controls. The MIT ``Future of Coal'' report and a 
forthcoming report by the National Coal Council endorse this 
fundamental measure. Realization of this opportunity will require a 
sustained R&D commitment and substantial investment in demonstration 
facilities. EPRI, DOE, Ohio Coal Development Office, and equipment 
suppliers have a program in place.
    EPRI and others believe that CO2 capture and 
sequestration (CCS) technologies for coal-based power plants will be an 
indispensable technology for achieving the deep cuts in man-made 
CO2 emissions needed to stop, and ultimately reverse, 
atmospheric build-up. CCS technologies can be feasibly integrated into 
all types of new coal power plants, including integrated gasification 
combined cycle (IGCC), pulverized coal (PC), circulating fluidized-bed 
(CFB), and variants such as oxy-fuel combustion. No advanced coal 
technology is economically preferred for adopting CCS, and the field of 
CO2 capture technology options is evolving quickly at small-
scale, but large demonstrations are vital. Sites for long-term geologic 
storage of CO2 are regionally available throughout much of 
the United States. Yet, there are major challenges to be overcome--both 
technically and in terms of public policy--before geologic storage of 
CO2 can be applied at the broad scale needed. Specifically, 
multiple large-scale (>1 million tons) demonstrations need to commence 
as soon as possible. Legal and regulatory frameworks need to be 
established, particularly with respect to long-term ownership and 
liability.
    RD&D pathways to success have been established collaboratively by 
EPRI, DOE, and industry groups. The RD&D funding needs are a 
significant step up from current levels, but within historical 
percentages for government agencies and private industry. Given the 
long technology development and deployment lead times inherent in 
capital intensive industries like energy, investment and policy 
decisions must be made now or we risk foreclosing windows of 
opportunity for technology options that we expect will prove 
tremendously valuable in a carbon-constrained future.

                     Biography for Stuart M. Dalton
    Stuart M. Dalton is a Director in the Generation Sector. His 
current research activities cover a wide variety of generation options 
with special focus on emerging generation, renewables, and coal-based 
generation, emission controls, and CO2 capture and storage.
    Mr. Dalton joined EPRI in 1976 as a Project Manager focused on 
SO2 control and later led this area for 20 years, 
additionally working on integrated emission controls for NOX, mercury, 
and particulates. He helped lead industry efforts to reduce costs, 
improve reliability, and apply these technologies.
    Before joining EPRI, Mr. Dalton worked at Pacific Gas & Electric 
evaluating new generation options (coal gasification and conventional 
coal), refuse firing, and NOX control retrofits. Prior to that he 
worked at Babcock and Wilcox focusing on power plants and emission 
controls.
    Mr. Dalton holds a BS in chemical engineering from University of 
California, Berkeley.
    Mr. Dalton helped create the EPRI CoaIFleet for Tomorrow program 
and, more recently, helped develop CO2 capture and storage 
work as well as EPRI's ocean energy program.
    The U.S. State Department has designated Mr. Dalton as one of two 
official U.S. Asia Pacific Partnership (APP) industry delegates to the 
Cleaner Fossil Task Force. In addition, he is leading EPRI's 
contribution to the National Coal Council report on CO2 
Capture and Storage and the Coal Utilization Research Council's CURC/
EPRI Roadmap.

    Chairman Lampson. Thank you. Mr. Hill.

   STATEMENT OF MR. GARDINER HILL, DIRECTOR, CCS TECHNOLOGY, 
                     ALTERNATIVE ENERGY, BP

    Mr. Hill. Mr. Chairman, ladies and gentlemen, I feel 
honored to be invited here today to talk about CO2 
capture and storage. I am indeed heartened that the Science and 
Technology Committee is holding a hearing on this technology, 
given the potential it has to play a critical role in helping 
address the climate change problem.
    A number of the elements of CO2 geological 
storage have been practiced for over 30 years in activities 
such as: Enhanced Oil Recovery (EOR), where we typically use 
CO2 to inject into oil reservoirs and flush more oil 
recovery; in the gas storage operations, where gas is stored 
underground, so we have availability and operability of the gas 
system; and in acid gas injection operations. Something on the 
order of 20 million tons of CO2 per year is 
currently injected into geological formations for EOR, so we 
already have a lot of experience.
    So, what have we learned about CO2 geological 
storage over this time and through subsequent technology R&D? 
Well, we know the best rocks for CO2 storage are 
depleted oil and gas fields and deep saline formations. Now, 
these are layers of porous rock, typically very deep, below a 
kilometer, and they are located under an impermeable rock known 
as a caprock, which acts as a seal to the main reservoir. The 
Intergovernmental Panel on Climate Change, the IPCC, has 
estimated the technical potential for CO2 storage is 
likely to exceed 2,000 gigatons or 2,000 billion tons of 
CO2, with the largest capacity likely to exist in 
saline formations.
    So, given that today's CO2 emissions are 
approximately 24 gigatons of CO2 from fossil fuels, 
geological storage has the capacity to store about 70 to 100 
years of all emissions from fossil fuels. On the other hand, 
others have estimated that CCS has the potential to contribute 
a quarter of the emission reductions required to address 
climate change, and in that scenario, you can envision 400 
years of CCS storage.
    In addition, a critical thing to remember about CCS is its 
flexibility and adaptability. And when CO2 is stored 
through the use of an EOR operation, as I discussed earlier, 
there is a genuine win/win for the environment and energy 
security.
    But what are the outstanding risks in the matter of 
CO2 storage? Well, it turns out this is not 
dissimilar to today's oil and gas industry. Local health, 
safety, and environmental risks associated with geological 
storage can be comparable to the risks of current activities, 
such as natural gas storage, EOR, and deep underground disposal 
of acid gas, provided best practice is applied in four keys 
area.
    The first one is site selection. The second one is the 
design of the storage and the operation of the storage 
facility. The third one is putting in place a robust monitoring 
program to validate your understanding of the storage system, 
and the fourth one is site abandonment, so you have integrity 
and seal of that storage site.
    Now, over and above these four areas, there are two 
critical frameworks I think are necessary to have managed these 
risks, and ensure we have consistency in the way CO2 
is stored. And one is the important regulatory framework for 
CCS, and the second one is a CO2 storage site 
certification framework, so we have a consistent standard 
applied.
    So, what are the things we should consider when selecting a 
storage site? Well, I think there are three primary things to 
bear in mind. The first one is capacity. Does the site have 
enough space to store a large amount of CO2? The 
second one is injectivity. Can you actually get the CO2 
in the rock and actually fill it up? And the third one, 
importantly, is integrity. Will the site store the CO2 
for the timeframe required?
    So, that means we need to understand the competence of the 
structure, the stratigraphic trap, you need to understanding 
the faulting within geological structure, because that could 
contribute to a leak or, indeed, compartmentalization of the 
rocks, you don't get access to all the pore space. You need to 
understand the geochemistry, the number of wells you need to 
store the CO2 and the design of the wells, so you 
have integrity for the life of the installation. But as I said 
before, a key element is the performance prediction, and we 
have to have a monitoring and verification program to validate 
the understanding of the storage site.
    Now storage, secure storage, actually increases over time, 
and that occurs through the interaction of four different 
trapping mechanisms. Some can be engineered to enhance the 
trapping, and hence, is important to understand the role that 
each of these mechanisms play when selecting a storage site. 
So, the first one, as I have mentioned, is structural trapping, 
where you have an impermeable rock above the formation, which 
actually physically traps the CO2 moving up.
    The second mechanism is called residual phase trapping. 
That is simply CO2 going into like a sponge. You 
have a sponge you have in your bath that you fill with water, 
sinking the CO2 in a rock, the CO2 goes 
into the pores in that sponge in that rock and gets trapped 
between the pore, and becomes totally immobile, just like you 
can't get the water out of the sponge unless you squeeze it.
    The third one is solubility, and that is where your 
CO2 dissolves in water, in your fizzy water, and 
what happens is the density of that water increases, so that 
water, then, sinks to the bottom of the reservoir, and can't 
possibly come out, because of the density difference.
    And the fourth one is mineral trapping, and that is where 
the CO2 reacts with some of the minerals in the 
formation, and you get physical hard scales forming, so it is 
physically trapped in a solid form, and hence the security of 
storage increases with time.
    So, what steps remain to be taken so we can design long-
term carbon sequestration projects? Well, clearly, technology 
development must continue, and has an important role to play, 
but my sense is the time is now right to embark upon large-
scale demonstration projects, and I would say that is a million 
tons or more per year projects. And it is important we 
demonstrate and we look and we try to demonstrate in a number 
of different types of reservoirs in different locations. And we 
need to truly learn by doing at scale.
    This needs to be done in a managed way by something like a 
deployment strategy, which is a framework or plan that is 
consistent with a clear objective that will be achieved by a 
certain point in time. We need to set a goal and put in place a 
plan to achieve the goal, being clear and transparent on the 
conditions of satisfaction required one way, so we can secure 
the public's confidence in this technology.
    It is clear we need to put in place regulations and policy 
measures that will allow geological studies to happen. Industry 
needs a regulatory framework, so that the operating conditions 
are clear, and industry needs a policy framework so we can 
define the necessary business and commercial conditions for 
CO2 storage. We need to also identify and remove 
roadblocks to technology, and I will give you two examples.
    One roadblock, potentially, is what happens to any 
liability associated with CO2 storage after a 
storage site is full and safely abandoned. Another example 
could be who owns the pore space? The number of laws in the 
U.S. are unclear in some cases about ownership of the very pore 
space in the rocks that will be used for storing 
CO2. So, removing these barriers, and a deployment 
strategy that is open and transparent, with the appropriate 
regulations, I think are really important to convincing public, 
regulators, and governments alike that CCS is a safe and 
important technology to help solve climate change.
    Ladies and gentlemen, it is time to get into action. It is 
time to get on with the job. This technology is available now, 
and with some help, we can make it happen at scale. And this is 
actually being demonstrated today by BP, who have announced two 
hydrogen power projects which will utilize CO2 
capture and geological storage to use carbon power from fossil 
fuels.
    Thank you very much.
    [The prepared statement of Mr. Hill follows:]
                  Prepared Statement of Gardiner Hill
    Chairman Lampson, Ranking Member Inglis, thank you for inviting me 
to testify here today on carbon capture and sequestration. I am 
Gardiner Hill, Director of CCS Technology at BP, and a petroleum and 
civil engineer by training.
    For those of you who don't know, BP has made a commitment to 
investing $8 billion over the next 10 years in alternative energy--
including wind, solar, and fossil-fuel powered power plants with carbon 
capture and sequestration (CCS). We have announced two projects using 
CCS--one in Scotland, the other at our Carson refinery in California.
    BP, and the oil and gas industry generally, has more than thirty 
years of experience injecting carbon dioxide in oil and gas reservoirs. 
We do so every day for enhanced oil recovery-injecting CO2 
into depleted oil reservoirs, recovering the remaining oil, and 
inevitably leaving CO2 behind. In other words, CO2 
storage is a technology that is available today and we know that it has 
the potential to play a significant role in helping to reduce CO2 
emissions into the atmosphere, helping to combat climate change.
    My role today is to explain how CO2 stays underground. 
It is important to understand that many natural geological stores of 
CO2 have been discovered underground--often by people 
looking for oil and gas. In many cases, the CO2 has been 
trapped underground for millions of years in geological traps, plus 
CO2 is also found indigenous in many oil and gas fields, 
where is has been stored underground naturally for millions of years. 
It is true that under certain circumstances, CO2 does leak 
naturally from underground. Indeed the world's natural carbonated 
mineral waters, long prized and bottled for drinking, come from natural 
CO2 sources. The reasons why some rock formations trap the 
CO2 permanently and some do not are well understood and this 
understanding will be used to select and manage storage sites to 
minimize the change of leakage.
    The best rocks for CO2 storage are depleted oil and gas 
fields and deep saline formations. These are layers of porous rock, 
such as sandstone, more than half a mile underground, located 
underneath a layer of impermeable rock, or cap-rock, which acts as a 
seal. In the case of oil and gas fields, it was this cap-rock that 
trapped the oil and gas underground for millions of years.
    Depleted oil and gas fields are the best places to start storing 
CO2 because their geology is well known, and they are proven 
traps.
    Deep saline formations are rocks with pore spaces that are filled 
with very salty water--much saltier than seawater. They exist in most 
regions of the world and appear to have a very large capacity for 
CO2 storage. However, the geology of saline formations is 
currently less well understood than that of oil and gas fields and so 
more work needs to be done to understand which formations will be best 
suited to CO2 storage, but the potential appears to be huge!
    So why does CO2 stay underground? As CO2 is 
pumped deep underground it is compressed by the higher pressures and 
becomes essentially a liquid, which then becomes trapped in the pore 
spaces between the grains of rock. The longer the CO2 
remains underground, the more securely it is stored. There are four 
different ways that CO2 gets trapped underground.
    The first mechanism is called structural storage. This can be best 
demonstrated by BP's joint venture with Sonatrach called In Salah, 
which is a natural gas development in Central Algeria. At In Salah, the 
natural gas produced from the deep rock formations is a mixture of 
methane (CH4) and CO2. Once it reaches the surface, the 
natural gas is separated into methane and CO2. The Methane 
gas is pumped North to Europe, while the CO2 is pumped deep 
underground--back into the rock formations from which the natural gas 
was originally extracted. One million tons per year of captured 
CO2 is injected and stored in this way. When it is pumped 
deep underground, it is initially more buoyant than water and will rise 
up through the porous rocks until it reaches the top of the formation 
where it is trapped by an impermeable layer of cap-rock, such as shale 
at the In Salah field. The cap-rock that kept the natural gas in the 
rock formation for millions of years keeps the liquid CO2 
stored in the underground reservoir. The wells that were drilled to 
place the CO2 in storage can be sealed with plugs made of 
steel and cement.
    The second mechanism is where CO2 gets trapped in the 
rock pore space through what is known as residual trapping. In this 
instance, the reservoir rock acts like a tight, rigid sponge. When 
liquid CO2 is pumped into a rock formation, much of it 
becomes stuck within the pore spaces of the rock and does not move.
    The third mechanism is called dissolution storage. In this 
instance, CO2 dissolves in salty water, just like sugar 
dissolves in tea. The water with CO2 dissolved in it is then 
heavier than the water around it and so it sinks to the bottom of the 
rock, trapping the CO2 indefinitely.
    And finally, the fourth mechanism is when CO2 dissolves 
in salt water, becoming weakly acidic and reacting with the minerals in 
the surrounding rocks, forming new minerals as a coating on the rock--
much like shellfish use calcium and carbon from seawater to form their 
shells. This process effectively binds the CO2 to the rocks, 
trapping it there.
    We have the technology and the knowledge to get started on storing 
carbon underground. BP, in partnership with Edison Mission, has 
announced a CCS project at our Carson refinery in Southern California. 
We will be taking petcoke, a refinery byproduct, and gasifying it. The 
resulting hydrogen will be used to power a 500 megawatt power plant, 
and the CO2 will be stored underground, probably via an 
Enhanced Oil Recovery process (EOR), which is the mechanism I outlined 
at the start of the testimony in which industry has over 30 years 
experience. We know that CCS is part of the solution to the climate 
change problem, i.e., ref. IPCC special report and Princeton Wedges 
analysis, etc.--estimates are that CCS technology has the capability to 
contribute around a quarter of the emission reductions needed to get to 
environmental stabilization. We have the technological know-how to do 
this, we need the policy and regulatory framework to enable its 
deployment.
    Thank you and I welcome any questions you may have.

                               Discussion

                       Carbon Sequestration Risks

    Chairman Lampson. Thank you very much. We will now begin 
with our first round of questions, and I will recognize myself 
for five minutes. And I would start with a whole bunch of 
questions at one time, if you will forgive me for doing this, 
and do them as best you can, and I would like to ask Mr. Bauer, 
Dr. Finley, and Mr. Hill to respond to these.
    I understand that CO2 storage is a technology 
that is available today, as we have heard, and could play a 
significant role in reducing CO2 emissions into the 
atmosphere. Do we know what the probability is of a carbon 
release from a geological site? What research and data are 
available to understand the environmental and human health and 
safety risks? Are there well established risk assessment 
methodologies for geological storage of CO2? Let me 
start with those, and then I am going to ask two more.
    Dr. Finley. Well, I think with regard to the probabilities 
of release, I think yes, there is a probability of release. It 
is very difficult to quantify at this point in time. The 
natural gas storage industry has had many very safe and 
operational natural gas storage facilities. For example, we 
have one in Champaign County, Illinois that stores 150 billion 
cubic feet of flammable natural gas over an area of 25 square 
miles, and that facility has been in place since the early 
1970s, and to the best of our knowledge, never has had a leak 
to surface or a problem.
    So, we have some analogies out there. We need to take 
advantage of those analogies, and I think with the advent of 
the large-scale testing that is being proposed here, and that 
we are moving toward on the regional partnerships, it is really 
going to give us an opportunity to put in place a series of 
sensors, observation wells, and the like, that I think will 
really begin to try and take this largely qualitative 
understanding, and move it over into the quantitative arena, as 
you suggest.
    Mr. Bauer. I would agree with that, and I think Gardiner 
Hill did a great job of describing basically what a reservoir 
would be, which is really not a void. It is a rock, it is a 
permeable rock, and many people get concerned about a rapid 
release, but from a permeable rock, it doesn't just spring out 
in tremendous force. To be a volcanic void, and there has been 
a couple incidents in history recorded, where a volcanic void 
erupted, with CO2 being released in a low-lying 
area, and there was a concern, but that is not the kind of 
capture area, plus the capstone rock being very important.
    We do have data, the regional partnerships have done some 
great things in the first two phases, at both analysis and 
collecting data, but the third phase, which we are entering 
this year, is to do projects towards the million ton per year 
level, and to catch, gather greater data for that. On the area 
of risk assessment, there are abilities to do risk assessment. 
The application to this particular arena is not really done, 
except from the standpoint, I think, and Gardiner, maybe you 
could speak to the EOR and the risk assessments about there, 
that might be of enlightenment to you.
    Mr. Hill. Thank you very much. I think this is all about 
risk management, actually. And the way we approach this is by 
taking fundamental review of the risks, and making sure these 
are managed adequately. But let me start by saying there is a 
lot of experience. I mean, there is many examples of gas 
storage, which is clearly more dangerous than CO2, 
because of the increased buoyancy and the flammability of gas, 
many years of EOR, and indeed, we actually have a number of 
CO2 natural gas fields that exist, or CO2 
natural reservoirs that exist in the U.S., that primarily are 
used today for supplying CO2 for EOR.
    So, we can actually go and look and study these CO2 
natural reservoirs that have occurred for millions of years, 
and why CO2 has stayed there for millions of years. 
And indeed, we have done studies to undertake the performance 
of the natural gas storage system, and there is examples in 
Europe where there is a very large natural gas storage system, 
actually under the City of Berlin itself. So, there is real 
examples of where gases, like CO2 and perhaps even 
more volatile, are actually stored in fairly public places very 
safely and with a great track record.

                        Regulatory Requirements

    Chairman Lampson. Okay. Let me interrupt you, because I 
have got 50 seconds left, and I want to try to be a little bit 
better on my timing this time.
    Let me ask the last two questions of you for this 
particular section for me, and then, I will catch something 
else a little bit later, but who should manage and monitor the 
sequestration sites, and secondly, does the EPA have good 
regulatory structure in place to adequately address the review 
and oversight necessary for large-scale carbon sequestration?
    Mr. Bauer. On the matter of who should regulate, I won't 
take that one on directly, because of my position, but we are 
working with the EPA to put in information and to prepare 
regulatory requirements. They do not presently have one of 
sequestration, they do have it for injection wells. There was a 
letter of guidance released March 7 of this year from EPA, 
giving direction of large-scale injection, but the long-term 
storage is not framed properly yet.
    Chairman Lampson. Dr. Finley or Mr. Hill, would you 
comment?
    Dr. Finley. Yeah, I think, as Carl mentioned, yes, the U.S. 
EPA has issued these guidelines looking at, classified as 
experimental under the underground injection control 
regulations, as a place to start. I think the Interstate Oil 
and Gas Compact Commission has been working now for several 
years, looking at the State regulatory framework, because after 
all, under UIC, states that have primacy, for example, do 
regulate as Class 2 the wells that deal with oil and gas and 
EOR, which Gardiner has referred to.
    So, I think basically, I think the States need to have an 
important role in it, but the exact framework of that role has 
yet to be defined.
    Mr. Hill. Yes. I would validate that. I think it is an 
important thing to tackle regulations, I think, when you take 
groups together, to make sure we have the right people who can 
write the right regulations.
    We are involved in helping, we would like to be involved in 
helping develop these, given the experience we have through EOR 
and through CO2 storage, like in Sowerfield, where 
we are injecting a million tons per year of CO2 
which is stored annually.
    Chairman Lampson. Thank you very much. Ranking Member 
Inglis, recognized for five minutes.

                       Carbon Sequestration Sites

    Mr. Inglis. Thank you, Mr. Chairman. Now, I am a commercial 
real estate lawyer, not a scientist, which will become obvious 
in the midst of these questions that I am about to ask.
    But one of the things you say in real estate, you know, is 
three things determine the value of real estate, location, 
location, location. And so, the question that I have about the 
geological formations is how common are they, and are they 
located in places that are usable? I mentioned in my opening 
statement the Duke power plant in South Carolina that may be a 
coal-fired plant. How readily available are these locations for 
the kind of storage that we are talking? Anybody want to, 
whoever wants to take a shot at that?
    Dr. Finley. Well, I think, I mean it depends on the type of 
rocks. I was in Madison, Wisconsin two weeks ago, and listened 
to the Wisconsin State geologist proclaim very clearly that the 
State of Wisconsin has very limited opportunity to store carbon 
dioxide in the rock framework. I am afraid that is also the 
case for much of the Atlantic coastal plain, which you 
represent with regard to South Carolina. I got my Ph.D. at 
Columbia, and so, I have some knowledge of the geology of the 
State of South Carolina.
    But basically, it is the rock framework, but that is not to 
say that we are restricted locally within that rock framework, 
because after all, we have more than a million miles of natural 
gas pipelines in this country that deliver natural gas from our 
shore of the Gulf of Mexico to the State of Maine, for that 
matter. So, basically, I think what can be adapted is find the 
places where the geology is suitable, where it is safe and 
where it can be effective, and if you have places where the 
coal resources or the water resources are available, such that 
power generation is appropriate there, then we can build an 
infrastructure to move the CO2 to where it can be 
safely stored.

                     Carbon Dioxide Transportation

    Mr. Inglis. So, then, we would likely be talking about 
moving CO2, pipeline system. I guess a truck would 
not be effective, right, because there is a lot of it, so you 
got to move it, which the next question is, is the other thing 
about commercial real estate, as we say, you know, they are not 
making any more of it, which makes it valuable, real estate 
that is. And so, the question is how quickly before these 
formations are used up? What kind of capacity do we have?
    Mr. Bauer. Well, I think as Dr. Finley gave in his 
testimony, there are multiple hundreds of years of geologic 
storage capacity available. It goes back to location. They may 
not be always available where you are. I think as Gardiner also 
mentioned, making sure you have a sufficient reservoir when you 
start to meet your stand for longevity there, is also something 
to determine.
    So, the bottom line is there is plenty of storage 
available. The geographic location may not always be in the 
right place. You may have to pipeline to it. But for the 
Nation, about 97 percent of the areas that use coal power today 
have geologic storage within a reasonable distance, 50 to 100 
miles, at maximum, to be pipelined, many times, even right 
below a facility presently.
    Mr. Hill. Can I just add to that? I think this is actually 
a volume issue, and that if CCS is to make a contribution to 
climate change, then we are actually talking about huge 
volumes, and in my statement, I said it could contribute up to 
a quarter of the reductions required to help stabilize 
emissions. Now, even a quarter contribution is something like 
equivalent to 125 million barrels equivalent of oil, so that is 
an industry big as the oil industry. Currently the oil industry 
is about 18 million barrels per day, so if CCS is doing only a 
quarter of the reductions required emissions, you are talking a 
business, an infrastructure, at least equivalent at least 
equivalent to these oil industry, so it will be a big 
infrastructure requirement. At times, there are a number of oil 
and gas fields that are very suitable to store CO2, 
but there is actually a lot larger capacity in these deep 
saline formations, which turn out to be quite extensive across 
the U.S., and in fact, most of the world.
    Mr. Rencheck. I would like to add on that, regional 
partnerships, the importance of continuing the drilling into 
the saline aquifers. While we understand a lot about the oil 
formations and gas formations, these rock structures in some 
cases are 9,000 feet below the surface. At our Mountaineer 
Plant, we participated in the drilling of that, understanding 
the geology, and we think we need to do more of that, so we 
understand the geology at those deep levels.

                       Carbon Sequestration Atlas

    Mr. Inglis. I have more questions, but my time is almost 
up. Mr. Bauer, just to make sure, how much, you said within 50 
miles, we have what percent of the capacity?
    Mr. Bauer. When we did the Atlas, which Dr. Finley held up, 
and I have a couple digital versions I would be glad to leave 
with the Committee, it identified that there were plenty of 
reservoirs, and the regional partnerships cover about 97 
percent of the land mass of the United States, which also 
happens to coincide to about 97 percent of the power plant 
areas, and well within that realm, there is pretty much 
sequestration availability for most of those plants within a 
reasonable transmission framework, and going with what Gardiner 
said, we are talking mainly with saline aquifers, as well as 
oil and gas fields that would be expended or used for EOR 
before expending.
    Chairman Lampson. Mr. Costello, you are recognized.

                        CCS Technology Readiness

    Mr. Costello. Mr. Chairman, thank you, and I thank all of 
the witnesses for their thoughtful testimony.
    I would like to try and clarify a few points, and then, ask 
a few questions as well. One is that I think it is important to 
clarify that while CCS technology will enable our power plants 
to operate more efficiently, and enable them to not only 
operate more efficiently, but reduce emissions, that there are 
legitimate reasons why utility companies and the coal industry 
are not using the technology today, and until the technology is 
ready to be deployed on a commercial scale basis, I believe 
that a mandate from Congress to capture and store all carbon 
dioxide underground will, in fact, shut down coal plants across 
the country, which will, of course, drive up consumer 
electricity bills, and convert existing power plants to burn 
natural gas.
    Given the volatility of the oil and gas market, and the 
instability in the Middle East and the rising cost of oil and 
natural gas, I believe we should reject policies which move us 
toward greater dependence on foreign sources of energy, and 
instead, embrace policies and encourage the use of our domestic 
resources, such as advanced clean coal technology demonstration 
projects.
    The figures that I have from the Energy Information 
Administration in May of 2007, the cost per million Btu of oil 
is $7.66 per million Btus. Natural gas is $7.53, and coal is 
$1.73, so I think it is very evident, the cost differences in 
oil versus natural gas and coal. Today's hearing, of course, 
has shed some light on some of these issues, and also, brings 
out the fact that there are significant challenges to overcome, 
such as the readiness of the technology, the capital costs and 
long-term liability issues, which was touched on, and I think 
that we in the Congress must first address these issues before 
we can implement a CCS technology mandate.
    With that, I would like to pose a few questions, and to try 
and clarify a few points. And Mr. Hill, in particular, I read 
your written testimony, and you state that carbon dioxide 
storage, also known as sequestration, is a technology that is 
available today, and I wanted to clarify a point, and to make 
certain that I understand, that you are referring to carbon 
sequestration technology for enhanced oil recovery. Is that 
correct?
    Mr. Hill. No, I am not only referring to oil recovery. I 
think the technology for storing CO2 in oil and gas 
reservoirs independent of enhanced oil recovery is available 
today, and I could point, I can point to the two well examples 
of where that occurs. Under the North Sea, the Sax Formation 
has been storing a million tons per year of CO2 for 
ten years, and the Dust Development in Salah. It is also 
storing a million tons of CO2 per year in the bottom 
of a gas reservoir.
    Mr. Costello. Now, is anyone currently capturing CO2 
underground, on a full, large-scale basis in the United States?
    Mr. Hill. I am not aware of a full-scale application in the 
United States.
    Mr. Costello. Any of the other witnesses like to comment?
    Dr. Finley. There is a plant in North Dakota that captures, 
from gasification, not from power production, but from 
gasification of coal, about 2.7 million tons a year, and it is 
shipped north to an enhanced oil recovery, and there is some 
testing as to how much will stay in that oil recovery field. 
So, that is one application.
    Mr. Costello. Let me, there is a bit of, we have a briefing 
for Members on the issue of coal and some of the challenges 
that we have, and in sum, people believe that the technology on 
a large-scale commercial basis is available today. Others say 
that it won't be available until the year 2020, and I wonder 
if, in particular, if any of the witnesses would like to 
comment, beginning with Dr. Finley.
    Dr. Finley. Well, I think that would be a little 
pessimistic, in my view. I think, in view of the experience at, 
in Sleipner, which is the North Sea project, and Salah in 
Algeria, and the Weyburn Project, and the gas, natural gas 
storage, I think saying that we cannot do this until 2020 would 
be, in my view, a bit conservative.
    Mr. Costello. But would you agree that the technology is 
not on a commercial, full-scale basis, available?
    Dr. Finley. Well, let me ask, are you speaking of the 
capture at the power plant, versus the ability to put it in the 
ground? Capture at the power plant is not available.
    Mr. Costello. Right.
    Dr. Finley. That is correct. Ability to put it in the 
ground from a source, such as the Dakota Plains Gasification 
Plant, where we have a relatively pure stream available, that 
technology is there.
    Mr. Costello. And in your judgment, Dr. Finley, how long 
will it be--of course, it is your--you have got to give your 
best guess, before the technology is available to capture it at 
the power plant on-site?
    Dr. Finley. I think we need probably, certainly, perhaps, 
six to ten years of intensive development to focus on that 
capture, basically to scale up some of the processes that we 
have seen today, and make them widely available.
    Mr. Costello. Two more quick questions, before I run out of 
time here. Would you agree that if, in fact, the Congress 
enacted a mandate to capture all, and to sequester underground, 
all CO2 emissions, in the short-term, that that, in 
fact, would shut down most of the coal-fired plants in the 
United States today, and force them to convert to natural gas?
    Dr. Finley. I think that would be a fair statement, yes.
    Mr. Costello. The last question, and I would love to hear 
from the other witnesses, but I am about out of time. Maybe we 
will have a second round, but Dr. Finley, some have suggested 
to Members of this subcommittee and to the Congress that, I 
have heard that we have a 250 year supply of coal. Others say 
that if we continue to use coal, and in fact, can sequester the 
CO2 and move forward in using additional coal, that 
we are going to run out of coal in the short-term, and I wonder 
if you might give your estimate as to the coal supply of the 
United States.
    Dr. Finley. Well, I think your number is correct, 
approximately 247 billion tons of defined reserves. We use 
about 1.1 billion tons a year, so that number is, indeed, very 
close. I think some of the Sasol process, Sasol experience in 
South Africa suggests we can get about two barrels of 
hydrocarbon liquids for each ton of coal. I think we could 
easily move to perhaps produce as much as two million barrels 
per day of liquids from coal, and I still think we would easily 
have 100 years of coal to do that, in addition to having the 
coal available for electric generation that we would need over 
the next 100 years.
    Mr. Costello. I thank the Chair for being generous with my 
time, and thank the witnesses.
    Chairman Lampson. Very welcome. We will get you back 
somehow. Mr. Neugebauer, you are recognized.
    Mr. Neugebauer. Well, I thank the Chairman, and like the 
distinguished Ranking Member, he is a real estate lawyer, and I 
am a real estate developer, so I don't know if I am going to be 
able to contribute much more than he did to this discussion.
    I think I am going to start with a fundamental question and 
just for my own edification, if I had two electric power plants 
sitting side by side, one of them using natural gas, and one of 
them using coal, what is the ratio of CO2 being 
emitted by those two plants? Mr. Dalton.
    Mr. Dalton. You would roughly get about 2,000 pounds per 
megawatt-hour from a coal plant, conventional design or 
gasification design, without capture. And you would roughly get 
about 800 pounds per megawatt-hour from a natural gas plant, 
combined cycle.
    Mr. Neugebauer. So, it is a substantial difference.
    Mr. Dalton. Correct.
    Mr. Neugebauer. And so, while we have got you in the queue, 
from your testimony, my impression is that post-combustion 
CO2 capture not only reduces the output of 
pulverized coal, therefore, adding to the cost, but also, adds 
to the cost, due to the additional technology, transportation, 
and storage requirements. Is that accurate?
    Mr. Dalton. That is accurate. We estimate that both the 
energy use and capture, and the compression energy, primarily, 
that is used to get the CO2 up to the point where it 
becomes almost like a liquid, about half the density of water, 
it is transported through a pipeline, that energy can roughly 
run from, if you used today's technology, 20 to 30 percent of 
the overall energy of the plant. Again, we are looking at a lot 
of new technologies, both for compression and for capture, that 
will reduce that, but that is the kind of range that we are 
looking at.
    Mr. Neugebauer. So, I have got to have 120 percent more 
capacity with that process, to produce about the same amount of 
energy, without it, and so, and at the same time, I guess I am 
creating more CO2 to be dealt with.
    Mr. Dalton. And you are using more coal, correct.
    Mr. Neugebauer. So, what--for that to be a viable option 
for the future, what kind of research needs to begin to, or is 
research going on to try to make that a more efficient process?
    Mr. Dalton. There is research going on. Carl Bauer referred 
to several pieces of that work that is going on. There is 
research going on on both the, if you will, the chemical plant 
that is in front of the power generation, which is 
gasification, and the chemical plant that is in the back of a 
more conventional plant, to capture the CO2. 
Unfortunately, we haven't found anything yet that is the 
perfect absorbent material, that grabs it very easily, captures 
it very easily, and then, when you want it to, wants to let it 
go very easily. If it is easy on the capture side, it doesn't 
tend to want to let it go, and this is what takes all the 
energy, is to try and make it let go of the CO2.
    Mr. Neugebauer. Yes, Mr. Rencheck.
    Mr. Rencheck. I would tell you that we are working on 
demonstration projects that would take those types of 
technologies that Stu was talking about from a pilot phase to 
an advanced phase, and we are hoping to get the energy 
penalties down to the 10 to 15 percent range. And the purpose 
of the demonstration is to do it at scale, and understand how 
it will behave on the back of the plant.
    We are also looking at building IGCC plants which, in order 
to advance that technology, we are going to have to build four 
or five, six of these plants at a commercial scale, before we 
understand how they can more efficiently and more effectively 
be utilized.

                        Other Uses for CO2

    Mr. Neugebauer. Mr. Finley, you indicated in, that in 
my part of the world, West Texas, we have been using CO2 
for tertiary and secondary recovery of oil very, very 
successfully, and I assume without much hazard to the 
environment and to the region. I guess the other question is, 
what kind of research is going on where we could, rather than 
just putting this CO2 in the ground and disposing of 
it, use CO2 for other kinds of activities? Is any of 
that kind of activity going on?
    Mr. Bauer. Yes, sir. There is some other work looking at 
using CO2 for more rapid plant growth, algae growth, 
taking the algae as a quick uptake of CO2, and then 
converting it to a biodiesel. There is a couple of different 
experiments around the country. Arizona Power Service is doing 
on a fairly large scale off of a plant, and they are moving it 
up to Four Corners area right now. There are a couple others I 
am aware of, where they use a pond rather than a bio-reactor, 
and those seems to hold promise, although the magnitude of the 
CO2 generated across the Nation, that would only be 
one of the tools, it would not solve the problem totally. But 
they are looking at using CO2 as a working fluid, to 
capture energy and move it elsewhere, and in fact, even oxy-
combustion plants previously mentioned, looked at recycling 
CO2 as part of the working fluid in operating the 
plant and keeping it cooler.
    Mr. Neugebauer. I thank you and thank the Chairman.
    Chairman Lampson. Thank you, Mr. Neugebauer. Ms. Giffords, 
you are recognized.

                     Western Regional Partnerships

    Ms. Giffords. Thank you, Mr. Chairman. I realize I wasn't 
here for the earlier questions and some of the testimony, but I 
hail from the great State of Arizona, where 90 percent of our 
electricity in the City of Tucson is generated from coal.
    Over 50 percent of our state's energy is generated from 
coal, but we are the fastest growing state in the Nation, and 
new coal plants are being proposed for Southern Arizona and 
across the State as well.
    I would like to see Arizona transition from coal to clean, 
renewable energy. However, I recognize that for the foreseeable 
future, that carbon capture and sequestration could help us 
reduce emissions in the meantime. So, I am curious to the 
barriers that we have in front of us in Arizona. I am curious 
about the environmental benefits and the costs, and also, some 
of the political obstacles that we have to overcome to make 
this a reality. And for anyone on the panel to answer, please.
    Mr. Bauer. Well, if you are talking Arizona specifically, 
there are, as I am sure you are aware of the geological 
resources to put CO2 in and store it, so those 
possibilities are there, but I think you made a very important 
point in your question, which is the political, and I might say 
the public receptivity to this. And this is one of the reasons 
the regional partnerships were formulated, to both understand 
the challenges in the geographic locations as well as the 
geologies, but also to work across the States that are part of 
it, to work with the communities and the academia to 
communicate what they find and what the challenges and what the 
opportunities are, so that the public acceptance and political 
acceptance would be there, should this process turn out, as it 
seems to be, to be a very viable solution.
    So, I think part of it is education, and then part of that 
education, as you again wisely observed, is to go where we 
would like to go, as far as renewables, will take many decades 
to raise the quantity capability. How do we keep the economy 
viable while we do that? We are going to have to use what we 
have, which is basically coal, natural gas, and others, which 
are more carbon intensive.
    Mr. Dalton. I would like to add that we have been working 
with the WESTCARB Regional Partnership in the West. There is 
some small-scale work being planned with Salt River Project as 
one of the organizations, working with, again this is the 
small-scale type of work that the regional partnerships has 
been excellent at setting out. It helps in understanding the 
mechanics, the monitoring, the verification. It helps in 
understanding the public perception issues as well, but there 
are geologies that run throughout certain parts of the West 
that are somewhat similar, and so, there should be quite a bit 
learned from any large-scale work that follows on wherever that 
is in the West, that the geologies are somewhat similar, to my 
understanding, as a chemical engineer, not as a geologist.
    Mr. Rencheck. And I would offer that the initial approach 
to improved efficiency as a coal generating plants are very 
important, and that is the reason for advancing technology such 
as the ultra-super critical plant, as well as the IGCC plants. 
And also, the existing fleet can also be improved from an 
efficiency perspective, but at times, it runs headlong into NSR 
regulations about improving border functionalities, so you 
could advance the existing fleet efficiency if we could get 
better clarity around new source review requirements.

                            Funding Concerns

    Ms. Giffords. And Mr. Chairman, if we could just follow up 
there. I am curious in terms of the actual costs, and where 
those costs would be shouldered. Is this--would--privately 
shouldered, publicly shouldered? Can the government step in and 
be helpful here?
    Mr. Rencheck. On the projects we are proposing, we are 
looking for a partnership between public and private funding. 
We are working also with technology providers who are also 
putting some of their money upfront in the development of 
technologies.
    But it is quite expensive, and any one entity trying to 
push this forward by itself isn't going to be able to do it, so 
it does need to be a partnership. We do need to have incentives 
and funding to be able to progress technology, especially if we 
are looking for it to progress in an expedient manner.
    Mr. Dalton. One other point, I am not sure if you were here 
for the testimony that I gave, but I mentioned that for a 
current technology on the pulverized coal plant, adding capture 
and storage might be an increase of 60 to 80 percent in the 
whole cost of generation, and for an IGCC, possibly 40 to 50 
percent.
    Now, a lot of research, federal and private efforts, are 
going toward reducing that cost, but right now, it is a very 
significant cost. Now, that isn't all of the retail cost of 
energy, obviously, but it could very significantly add, if it 
is today's technology.
    Mr. Hill. I would just like to reinforce a couple of 
points. I think the government has a very important role to 
play here to enable this technology to happen, and to happen 
quickly, because time is of the essence, and the key ones, I 
think, are regulations and policy, and the need for public/
private partnerships to co-invest and build these large, 
integrated projects.
    They are very large capital outlays, but for that, you get 
very large reductions in emissions, and that is one of the 
unique things about this. You get very large reductions in 
emissions for one very large power plant. The downside is there 
are large capital outlays, and that is why you need to have 
this public/private partnership sharing the risk and sharing 
the development of this technology.
    Ms. Giffords. Chairman, if I can just follow up really 
quickly, Mr. Hill, can you give us very specific examples where 
public/private partnerships of this magnitude have been created 
around other industries, and areas that we can possibly learn 
from?
    Mr. Hill. Well, I can give you a couple of examples where 
we were doing that on technology R&D. We have, we formed a 
public/private partnership, in fact, with the Department of 
Energy, probably about six or seven years ago now, where we 
really embarked upon a large program to develop new 
breakthrough technologies to reduce the cost of capture, and to 
prove that CO2 could be stored safely. And that 
involved eight different companies, the Department of Energy, 
the European Commission, and the Norwegian government, who have 
been working together over the last six years at developing 
these technology, and it has now got us to the stage where we 
are ready to deploy and really demonstrate that at scale.
    And I think that is a great example of where these public/
private partnerships have got into action and produced some 
really tangible results.
    Mr. Rencheck. I would also offer that FutureGen is off to a 
good start with public/private partnerships, and it also has an 
international flavor, with participation from both the utility 
companies, coal companies, as well as governments.
    Ms. Giffords. Thank you, Mr. Chairman.
    Chairman Lampson. You are welcome. Thanks, Ms. Giffords, 
and now, I will recognize Mr. Wilson.

                   Carbon Capture for Coal to Liquids

    Mr. Wilson. Thank you, Mr. Chairman. Gentleman, thank you 
for being here today. I represent the State of Ohio, or Ohio's 
Sixth Congressional District, which is coal country all along 
the Ohio River.
    We have some interesting things going on there, and I would 
sort of like to present them to you, and be interested in your 
comments. And the panel in general, not just a specific person.
    But we have a coal to liquid plant being proposed by the 
Baard Corporation, and it is going to be in Southern Columbiana 
and Northern Jefferson County along the Ohio River, but again, 
trying to tie together the Armed Services Contract, who will 
take the fuel for jet fuel, and be able to marry the two 
together, so that the fuel that is produced will have an 
automatic market for it. And again, trying to protect the 
investors, because we are looking at this thing long-term, not 
just something that if oil happens to hit $35 a barrel, we 
would have to be able to secure that investment.
    That is one thing we are hearing. Another one of the 
concerns--and we are very excited about that, I might add--we 
also have a new coal-fired electric plant, a couple of them in 
play right now, and we have a couple of retrofits that AEP are 
doing along this Ohio River corridor.
    The question or, to me, at least, the focus should be 
politically, or from the government, I should say, that if oil 
is the numbers that Congressman Costello said, which are just 
hugely different in what the coal can produce, it would seem to 
me that it would be wise to focus on the research and 
development of this at this point. It would be a much less 
expensive process than to continue sort of bantering around, 
for lack of a better term, but I am not sure, as a new 
Congressman, how we do that.
    So, I am not sure that you have all the answers to those 
questions, but the other thing I am hearing is sort of a mixed 
message on how we do the sequestration. One of them is, in one 
of my areas, we have a new process called Powerspan, that has 
been put in, and they have drilled a 9,000 foot hole in 
Shadyside, Ohio there at the Burger Plant, to do sequestration, 
and my understanding is that the hole gets smaller as it gets 
deeper. I missed the first part, as far as pipeline, and I 
believe, Mr. Chairman, what we were saying is that this could 
be piped off into other areas. It doesn't have to be 
sequestered right onsite. Is that what I am hearing there?
    The second thing, in ways of doing, or capturing the 
CO2, was that of the algae process, and my 
understanding in dealing there with the people at the Voinovich 
Center at Ohio University, we are talking about the algae being 
applied to, at least this is my understanding of it, large 
sheets of it, if you will, and then, the carbon would be 
captured, and could somehow be reused, then, as a coke in 
producing steel. So, just some of those thoughts, if perhaps 
you could help me get some clarity on those. Mr. Rencheck.
    Mr. Rencheck. We are trying to develop an IGCC plant in 
Meigs County, Ohio, and had applied for, instead of tax 
credits, the incentive tax credits were only enough to cover 
two facilities. Two facilities won't be enough to keep the IGCC 
technology advancing. We need to have more funding in that area 
to be able to advance those plants.
    As far as the Powerspan technology, it is very similar in 
the type of technology that is being produced by Alstom, who we 
have teamed with. It uses a chilled ammonia process for 
capturing CO2. With the hope of the chilled ammonia 
process, it would reduce the overall power requirements of the 
plant, where Stu had said, upwards of 30 percent. Again, we are 
hoping to get it to a power penalty of around 10 to 15 percent, 
so it would advance that. And funding is needed to move these 
projects forward as well, if we are expecting to do this in a 
timely manner.
    Mr. Dalton. Just to add, EPRI has also been working with 
the First Energy and Powerspan organization on their past work 
at the plant, and are involved in the planning for the next 
phase. This, again, is part of the regional partnership's work 
for injection of CO2 at the Burger station. We think 
that there are a number of promising technologies. When we did 
a recent screening, we came up with about three dozen different 
promising technologies, and I am sure we didn't cover them all. 
There are some that are still at different stages of 
development.
    This is an area where we think in parallel, not in the 
normal sequential arrangement of first you do the very small-
scale work, then you do the pilot, then you do the large-scale 
up, we are going to have to work on multiple technologies at 
the same time, with an aggressive R&D effort, and we have been 
putting together some of these different plans for different 
technologies. I have in my hand one that is called CoalFleet, 
we have a program called that, RD&D, Augmentation Plan for 
Integrated Gasification Combined Cycle Power Plants. This has 
been put in the public domain. We have others that we have been 
working on for combustion. We believe that there are lots of 
things that need to be pressed right now, and pressed rapidly, 
as a public/private partnership.
    Mr. Rencheck. As part of a regional partnership, we have 
also drilled a 9,000 foot hole, just further down the Ohio 
River on the West Virginia side, being able to inject in both 
of those locations will give us a very good understanding of 
the rock formations and the capability in the area, in the 
regional area, of being able to sequester and store 
CO2. So, we are looking to progress both of these 
projects as part of the regional partnership.
    Mr. Hill. One of the things, I think your other question 
was focusing on R&D, and how you get actually things done at 
this scale. One of the things I can share with this hearing is 
what is being done in Europe, and the European Commission have 
set up a technology platform for zero-emissions power.
    And I think two key things have come out of that, well, 
probably three key things have come out of that. One is a 
strategic research agenda, identifying all the research that is 
required. The second one, I think, is probably the most key, 
and that is a deployment strategy. What needs to get done to 
enable this to be in place and actually happening at commercial 
scale by a certain date? And the third one is setting a time 
when this will happen. And President Barroso, in the recent 
energy announcement, in fact, earlier this year, announced that 
by 2020, their plan is to have all fossil fuel power plants to 
require carbon capture and storage. Otherwise, they won't be 
permitted.
    So, I think that was, and I mentioned this in my statement, 
I think it is really important to have a plan and a target, and 
a research and deployment strategy to enable you to achieve 
that objective. And one of the things the platform in Europe 
has done is brought together government, industry, utilities, 
all sectors of the industry, as well as equipment suppliers, 
academics and engineers, to work with us together, given that 
context and the goals that have been set.
    Mr. Rencheck. Not deploying further coal generation would 
inhibit and retard the ability to make that generation more 
efficient over time. As Mr. Dalton said, working the 
technologies in parallel will help us to get to the end 
solution faster. And as an example, in IGCC technology, its 
first commercial plants will occur with AEP and with, 
potentially, Duke Energy in Florida at a 600-megawatt level. 
They have not been built yet in the States. Not to continue 
developing that will slow the development of the gasification 
process technology, as it integrates with the combustion 
turbine process.
    Mr. Bauer. If I may, Mr. Chairman. I know your red light is 
on, but----
    Chairman Lampson. Go ahead.
    Mr. Bauer. The DOE has had a plan, a roadmap, to go forward 
on these various challenges, and that is part of what the 
budget is based on. Of course, within the limited confines of 
funding availability, we have to make decisions, but the 
program both develops technologies for efficiency, as well as 
carbon capture, many of the things that were talked about, and 
have all been funded through the DOE. And the Powerspan 
technologies is in action, an NETL patent that was licensed to 
Powerspan.
    On the algae issue, there are multiple ways to capture, and 
I think part of the things you are hearing, Congressman, are 
that there are multiple pathways forward, and our funding level 
constraint for parallel production is part of what is slowing 
the process down. So, going back to what my friends here are 
saying, trying to do things in parallel costs more 
instantaneously than doing things in series.
    Chairman Lampson. Will you help us push for that additional 
funding?
    Mr. Bauer. I will do what I can do.
    Mr. Wilson. Thank you, gentlemen. Thank you, Mr. Chairman.

                               Efficiency

    Chairman Lampson. You are welcome. Thank you.
    I have a number of questions, and if you all will keep your 
answers as short as you possibly can, I might be able to make 
it through all of them.
    Mr. Bauer, how high do you believe the alternative 
combustion technologies DOE is researching, like oxy-
combustion, can push the efficiency of coal, energy efficiency 
of coal?
    Mr. Bauer. I think the issue on the oxy-combustion is we 
can get to several percentage points more efficiency. So, 
presently, the advanced power pulverized coal plants and IGCCs 
are equivalent in efficiency. I think with oxy-combustion, with 
some improvements in IGCC, they will both be in the 40 percent 
plus range over the next several decades. The thing that oxy-
combustion provides is to the savings on the capture side, 
because now, then you have a higher concentration of CO2 
to capture from a pulverized coal unit, which is one of the 
advantages the IGCC has. They have a higher concentration of 
CO2 in their stream. So, that begins to level those 
issues, as far as the price of operation.
    Chairman Lampson. What progress has your Advanced Turbine 
Program demonstrated over the last ten years, and how close are 
these technologies to commercial scale application?
    Mr. Bauer. I am going to ask Dr. Strakey to speak up, 
because that is his domain.
    Mr. Strakey. I think the Advanced Turbine Program has made 
some remarkable progress. Originally, it was directed towards 
natural gas, and resulted in the H-class turbines, which are 
the most efficient, largest machines that are now being 
demonstrated at multiple sites around the world.
    What we are trying to do in the coal program is take that 
same kind of technology, and adapt it for burning hydrogen, 
which is what you would have in a zero-emission plant. We are 
at some of the early stages of this work, and we hope to test 
some of that technology in FutureGen and other sites as well.
    Chairman Lampson. How close to commercial scale 
application?
    Mr. Strakey. Well, you can do it commercially now, but you 
will take a hit in terms of efficiency and emissions. So, the 
problem is how do you get back the couple points of efficiency 
that you would lose, and keep NOX emissions very low, in the 
parts per million, couple parts per million range, so these 
plants can be sited anywhere in the U.S.
    Chairman Lampson. Thank you. Mr. Rencheck, pulverized coal 
plants can achieve very high efficiencies with supercritical or 
ultrasupercritical steam pressures and temperatures that can 
reach 1,400 degrees Fahrenheit. You mention AEP's lead on 
development and deployment of more efficient coal power plants. 
I understand these extreme conditions can cause problems for 
the materials used in the power plants.
    Who is conducting the primary research in these areas? 
Could you explain some of those material issues? Is there 
sufficient investment in these advanced technologies, either 
from the federal or private?
    Mr. Rencheck. The easiest way to explain it, an existing 
subcritical plant metallurgy, if you take it to the 
ultrasupercritical level that we are building right now, at a 
little over 1,100 degrees, the piping system that would 
normally last 75 years, in a supercritical plant would probably 
last about two. So, the metallurgy advancements to get the 
1,400 degrees take quite a bit more research and development. 
It is primarily being pursued in Europe and Asia at this point 
in time, with a little funding in the U.S. It does need 
additional funding to be able to advance the metallurgies and 
technologies forward. There is some work going on with U.S. 
companies at this point, but it is not at a level that would 
advance it in the near-term.
    Chairman Lampson. Mr. Dalton.
    Mr. Dalton. I might add, under the sponsorship over the 
last about six years from the U.S. Department of Energy, the 
Ohio Coal Development Office and, with a team that includes the 
major U.S. boiler and now, turbine manufacturers, as well as 
specialists in EPRI as part of that team, and actually leads 
some of the technical work, we have been looking at some of 
those, at more advanced materials. There are very few 
materials, they also tend to be extremely high alloy, meaning 
high nickel, and for the same reason that we have taken the 
nickel out of the nickel in the U.S., it has gotten very 
expensive, it is very expensive for some of the alloy materials 
that are being used worldwide.
    And this could significantly increase the cost, limit the 
number of alloys that could be used, so what we are looking at 
is the design methodologies, the tests in the field, and right 
now, there is not enough to bring that to the full-scale 
demonstration and deployment stage. We are really limited to 
the materials work in the work that we are conducting right now 
with DOE.
    Mr. Rencheck. And I would just like to add, the vintage, 
where we are looking to build here over the next several years, 
are already operating in Germany and Japan. We are behind.
    Chairman Lampson. Mr. Dalton, in your testimony, you state 
that the significant energy consumption required by CO2 
separation processes and other emissions technologies can 
reduce a plant's electrical output by as much as 30 percent. 
Are there technologies that bring about enough production 
efficiencies so that the output losses from CO2 
separation are offset?
    Mr. Dalton. The technologies for capture will almost always 
use a significant amount of energy. However, with the 
advancements of efficiency, through things like we were just 
talking about in the ultrasupercritical designs, the H turbine 
design, as one example, the ion transport membrane for oxygen 
separation, put these things together, and you get a more 
efficient front end, if you will, and a less parasitic load, or 
a less consumptive load on the back end. The overall, we 
believe, can mean that in 15, 20 years, you are back up to 
higher efficiencies again. But there is some consumptive use.
    Mr. Rencheck. I would like to make one point, as a retrofit 
on an existing plant, there are steam requirements for the 
existing technology that can get to the point where the plant 
physically won't work, and looking at some of our existing 
fleet, we believe we can only get enough steam off the steam 
cycle to capture a maximum of 50 percent carbon.
    Chairman Lampson. Thank you. Would the work that Rick 
Smalley was doing at Rice University on carbon nanotechnology 
be--are you familiar at all?
    Mr. Dalton. There again, there are at least three dozen new 
processes. Some of them propose very low energy use or using 
other forms of energy, such as the algal growth, which uses 
solar energy as part of the overall energy balance.
    Chairman Lampson. Thank you all. You did good. Ranking 
Member Inglis, it is your turn.

                        Basic Organic Chemistry

    Mr. Inglis. Thank you, Mr. Chairman. You know, necessity is 
the mother of invention, but it is also true that invention is 
propelled by a can-do spirit, and the neat thing about being 
here and hearing you testify is it is obvious that you are out 
there trying to solve these things, and so, we are very 
fortunate to have people like you doing what you are doing.
    And maybe now you can explain to me the chemistry of carbon 
as said earlier I need to understand the science a little bit 
better. And maybe it would help me to have somebody tell me why 
it is that apparently, carbon wants to hook up with oxygen, 
right, and to get it to unhook, it takes some energy. But it 
must be possible to hook it with something else, to make it so 
that it isn't necessary to sequester it, or is it? I mean, is 
anybody working on something that would cause it to hook with 
something else, or is there nothing else that it likes to dance 
with?
    Mr. Bauer. Well, as you said, Congressman, carbon and 
oxygen seem to like each other. H2O, of course, is 
hydrogen and oxygen, but given the choice, more energy is 
released going to carbon dioxide than water, so in fact, 
shifting the gasification reaction to make more hydrogen, we 
pass steam through the system, and it hooks up with carbon 
monoxide, CO, to form water, I mean, to release hydrogen and 
have more oxygen and carbon combining, so the problem is that 
it is a lower state of energy required to have that bond of 
CO2, so therefore, it is very hard to break it apart 
once it is joined.
    It is possible, and in fact, some people are looking at 
taking CO2, and using it to reverse the process, 
which will take energy, but if the economics are right, because 
of the pain of CO2 in the world, you could possibly 
make a Fischer-Tropsch fuel out of that. That doesn't make 
sense in our present economy, because of the energy burden, but 
in the future, it may make sense, because the problem of 
CO2 could be so great that the economics drive it 
the other way.
    Mr. Inglis. In which case, the carbon itself has some 
value, if you could isolate it.
    Mr. Bauer. Yes, most of our fuel, and many other things 
that we use, carbon is an essential component of it.
    Mr. Inglis. Right.
    Mr. Bauer. Even biomass is basically because of its carbon 
value that we use it.

                             Carbon Capture

    Mr. Inglis. So now, maybe somebody can explain to me the 
thing that, I heard a presentation, and I didn't get it. So, 
maybe you can help me understand it, about how it is that, how 
pre-combustion CO2 capture works.
    Mr. Rencheck. The bottom line is the, in the gasification 
process, you are taking coal, and you are not oxidizing it or 
burning it. It is more like it is smoldering, and with that, it 
produces a gas. The gas is primarily carbon monoxide and water, 
and it is under pressure, so it is a pressurized gas stream. 
The way you would do that, then, is as syngas goes forward, you 
shift it, and when you shift it through a Fischer-Tropsch 
process, it creates basically hydrogen and CO2 in a 
pure stream. That CO2 stream is pressurized already, 
so now, to pump it in the ground takes a lot less energy to 
store it. And then, the hydrogen is used in the combustion 
turbine to generate electricity.
    Mr. Dalton. Let me try one other analogy. If I had a pretty 
good sized power plant, and I made this gas, I take a little 
bit of oxygen, not enough to burn it, but a little bit, I react 
it, I make something that looks like obsidian, volcanic glass, 
and it is inert. In the process, I make some hydrogen. The gas 
is under pressure, and it is high in concentration. I can 
literally put my arms around it, the size of a duct. However, 
at the back end of a power plant, the duct is more like the 
size of this room. It is very, very large, and you can just 
think it takes more equipment to literally get your arms around 
it. It is a much smaller, more compact, cheaper process to 
capture it in this pre-combustion, at pressure, with a higher 
concentration of CO2, than it is to capture it 
afterwards. But do you want your chemical plant in front or in 
back, because they are both really chemical plants.
    Mr. Rencheck. And in the back process, it is basically at 
atmosphere conditions, and in the combined cycle process, it is 
compressed down at over 200 pounds, well over 200 pounds.
    Mr. Inglis. Mr. Hill, did you want to add something to 
that?
    Mr. Hill. Yeah, I was just going to say the same thing from 
a different perspective. I mean, so pulse combustion is 
basically you burn the fossil fuels, and you have the exhaust 
gas, and you have to strip out the CO2 from the 
exhaust gas, and the challenge is the CO2 might only 
be a small part of that exhaust gas. It might 10 to 13 percent, 
if it is coal, or maybe three or five percent if it is gas, so 
you have got a huge volume, and you are trying to just pick out 
this 13 or three percent of CO2. That is why that is 
quite tricky and quite expensive.
    Pre-combustion is quite interesting, because pre-combustion 
is basically you are taking, you are developing a conversion 
process. You are converting gas, or you are converting a fossil 
fuel, putting it through a chemical conversion process to get 
some other state for that fossil you. And if you shift it the 
whole way by using steam, you get, eventually, CO2 
and hydrogen. But at other stages, there are other chemicals 
you can get before you get to the CO2 and hydrogen, 
so it is quite a flexible technology. You could produce syngas, 
which you could actually put in the gas distribution system. 
You could produce other chemicals for chemical processing, as 
well as also making hydrogen for power.
    So, pre-combustion is like a conversion process of fossil 
fuels to some other chemical state you would like that fossil 
fuel in. That does take a lot of energy, and the challenge is 
how you do that in the most cost-effective and efficient way.
    Mr. Inglis. And I assume the economics of that aren't quite 
there at this point. Is that right, or is that--how far away 
are we from the economics working on that sort of thing?
    Mr. Bauer. Well, I think as both Stu and I have suggested, 
that with gasification, we are looking at 30 percent increase 
in the cost of electricity, so that gives you a sense of the 
economics. With an existing power plant, or even a brand new 
pulverized coal plant, not oxy-combustion, because the 
advantage of the oxy is you have a higher concentration of 
CO2 again, because you don't put all the nitrogen in 
the rest of the air, and nitrogen is 70 percent of air.
    So, that is like 50 to 70 percent, depending on the design 
of the plant, the substantial increase in the cost of 
electricity. And I think what is important to realize is that 
electricity is a low value product, and that is dispatches, 
whoever has the lowest price sells it, so for someone like AEP 
to make an investment on a plant that they couldn't dispatch 
early and recover costs, is a prohibitive hurdle to get over on 
their part, and that is part of the real issue on trying to 
move forward on this.
    Mr. Rencheck. I would just like to add as well, in the 
combustion process for oxy, coal, and IGCC, one of the biggest 
cost drivers or inefficiencies of that plant is actually making 
the oxygen for partial combustion. If you have to take air and 
separate the nitrogen and the oxygen, you run it through these 
gigantic compressors, some of which have 45,000 horsepower 
motors, bigger than probably the size of this room, you 
actually have to make sure your grid is reinforced, just so you 
can start these things. They are massive pieces of equipment, 
where some of the R&D work that Carl was talking about, with 
membrane technology, that could separate the air into nitrogen 
and oxygen, would make that process much more efficient, and 
much more economical over time.
    Mr. Inglis. Thank you.
    Chairman Lampson. The Chair recognizes Mr. Udall.

    H.R. 1933, the Department of Energy Carbon Capture and Storage 
              Research, Development, and Demonstration Act

    Mr. Udall. Thank you, Mr. Chairman. I want to thank all you 
witnesses for being here. This is a really important and very 
interesting, it goes without saying, and just having been here 
a few minutes, it is clear that carbon capture and storage 
technology has real promise, particularly when it comes to 
utilizing these vast coal reserves that we have.
    The DOE, as you know, has been researching this 
opportunity, I like to think of it in that regard, through its 
R&D program, but I think that Congress could do more to move 
the technology forward, and to that, I have recently introduced 
a piece of legislation, H.R. 1933, entitled the Department of 
Energy Carbon Capture and Storage Research Development Act, and 
what I would like to do is ask you, Mr. Bauer, starting with 
you, if you think this approach would help validate the 
technology, and move it towards commercialization.
    I would, as you begin to speak, that Senator Bingaman has 
introduced a companion bill in the Senate, and there was a 
recent hearing that I am referencing with my question.
    Mr. Bauer. Thank you, Congressman. I am familiar with 1933, 
and Senate 962, which are companion bills, and I think both 
bills provide a great deal of opportunity and are very positive 
towards dealing with these issues. I appreciate the recognition 
in the bill of the cost severity of trying to pursue this, 
which in the Energy Policy Act of 2005, has lower numbers, but 
this is a substantial problem, and so, the increase that you 
have recognized in the numbers are very good, the recognition 
of the regional partnership and the contribution they are able 
to make, I think is essential for us moving forward.
    We have done a competitive process with both academia and 
environmental agencies, State agencies, and other agencies of 
the government, National Labs, and these regional partnerships 
have formed around that, and they have moved forward, and we 
are about to go into the phase of a million ton per year seven 
projects. I think you referenced that in the bill, and that is 
very exciting. So, overall, I think both bills provide the 
opportunity to move more rapidly and aggressively to overcome 
this challenge, and truly make it an opportunity.
    Mr. Udall. If anybody else on the panel would like to 
respond, I would welcome your thoughts.
    Dr. Finley. I think 1933 also addresses that issue, and I 
would like to echo the sentiments that Mr. Bauer indicated. I 
think it is really important now that we move forward with the 
large-scale aspect of this, and that takes additional funding. 
The equipment, for example, even for a modest so-called large-
scale test, 1,000 ton a day test, we need alone perhaps $12 to 
$14 million to install the equipment, large compressors that 
are very difficult to obtain. In fact, there is almost a year 
lead time just to order that equipment.
    So, I think funding of this effort is extremely important. 
I think where there is a much greater recognition, as a result 
of the three IPCC reports that have come out since February, 
and I commend the effort to move this forward, particularly at 
the large scale, and to fund those efforts at that larger 
scale.
    Mr. Udall. Anyone else on the panel, or Mr. Bauer, do you 
want another----
    Mr. Bauer. Yeah, I just wanted to add one other thing. I am 
trying to recall the many things in looking at the bill.
    Mr. Udall. Sure.
    Mr. Bauer. And I am hoping I am not going to be out of turn 
in saying this, sir, but to do these projects is going to take 
more than three years, and I am sure you realize that and 
understand the process, but I didn't want to be remiss in 
suggesting that this would be the end of the story. I wish it 
would be, but it is probably seven to ten years, depending on 
how successful we are, to get to the end.
    Mr. Udall. Well, we are here to improve the legislation 
that has been proposed, and that makes complete sense that 
three years is not the only length of time we should be 
considering. Anybody else on the panel? Mr. Dalton.
    Mr. Dalton. While I am not commenting on the bill itself, I 
would point out that capture is one of the big costs. It is 
almost as if you can look at two big issues, the cost in energy 
use of capture, and the effectiveness and assurance that you 
have storage well in hand. Those are the two big issues, and 
putting them together is one of the things that we think is 
very important as well. It is well enough to say that yes, I 
can, the car will perform this way, and the tires will perform 
that way, but you really do want to test them together. And in 
this case, I think that we want to make sure that large-scale 
capture and transport and storage are operated together, to 
make sure that there is good ability to do that, and operate 
the system that includes point-to-point transport, storage, as 
well as capture.
    Mr. Udall. Excellent point. Mr. Hill, and then we will come 
back to Mr. Rencheck.
    Mr. Hill. Yes, I just want to reinforce that point. One of 
the things that BP has been very active over the last three or 
four years, is actually studying in a great deal of depth the 
integration of capture and storage systems. Through the two 
projects we have proposed, one in Peterhead in Scotland, and 
the other one at Carson in Long Beach, California.
    And one of the key things we are learning is once we do 
this detailed work, is the integration of the various 
components of the overall process, in a way that will have a 
high degree of efficiency and a high degree of operability. So, 
I think there is only so much you can do by looking at 
individual components, and there really is a need now to build 
these very large-scale, integrated, commercial scale project to 
prove the integration of the various components, the 
operability, and the overall cost, and we will only discover it 
when we actually build them, and get really experienced, and I 
think that is the next step for us to take.
    Mr. Udall. Mr. Chairman, I see my time has expired. Is 
there time for Mr. Rencheck, or will we have another round, 
whatever works?
    Mr. Rencheck. We have provided projects that we are 
undertaking, and it will take it to scale, but as we talk about 
that, we need to also advance the combustion process and the 
pre-combustion process through ultrasupercritical technology or 
IGCC technology in addition to post-capture or capture and 
storage as well. Doing one without the other only thwarts the 
technology advancement going into the future.

                   More on Carbon Sequestration Risks

    Mr. Udall. These are very important points. Mr. Chairman, I 
had a couple other questions. I could submit them for the 
record, or I can direct them to the witnesses, depending on 
your timeframe.
    If I could, and if you all discussed this before I arrived, 
what is the probability of the carbon release from geological 
storage sites, and what research and data are available to 
understand the environmental and human health and safety risks, 
and are there well established risk assessment methodologies 
for geological storage of CO2? Easy questions, I am 
sure, given the smiles I see on people's faces, and I think Mr. 
Hill, Dr. Finley, and finely, and Mr. Bauer, you all have some 
qualifications to speak to. Dr. Finley, I am sorry, I have got, 
I see it is finely here and Finley here, so you correct me.
    Dr. Finley. That is correct. Well, that is an extremely 
important issue, and it is, in fact, one that DOE has funded 
work. The National Labs, Lawrence Livermore and Lawrence 
Berkeley, have both been working on this for some time, 
independent of the Regional Carbon Sequestration Partnerships. 
We are in the process of uptaking some of that knowledge into 
our partnership.
    I think you have to make the distinction between the so-
called catastrophic release that is often cited in the press, 
the Lake Nyos example, I mean, I don't think we would decide to 
put CO2, inject CO2 beneath a volcanic 
lake, which is a high risk situation, obviously, and in this 
case, it was natural CO2, in any event.
    The risks are just beginning to be quantified. There is a 
lot of detail work now beginning to look at this, especially as 
we move forward with the large-scale injections per se. 
CO2 is not flammable, it is not poisonous, but yet, 
you don't want to fill a room up with it, and walk into the 
room, and not move out. So, basically, you don't want it coming 
up, obviously, in people's basements and so forth.
    My feeling as a geologist is that the risk, there is the 
natural risk posed by the geology itself, and then, there is a 
risk posed by the facilities, such as wells. I think the risk, 
if we carefully site these projects, and we assess the geology 
extremely carefully, with geophysics and seismic, look to make 
sure there are no faults or fracture zones, I think that risk 
is relatively low.
    I think the larger risk, as we get many, many of these 
projects, is to make sure that the manmade infrastructure, the 
wells, pipelines, compressors, and so forth are done with the 
utmost care.
    Mr. Udall. Mr. Chairman, perhaps given the votes that have 
been called, we could submit the rest of the, others could 
have, on the panel, a chance to submit their answers for the 
record. And I have some additional questions I would like to 
submit for the record as well.
    Chairman Lampson. Without objection, you may do so.
    We want to thank all of you for appearing before the 
Subcommittee this afternoon. And under the rules of our 
committee, the record will be held open for two weeks for 
Members to submit additional statements and any additional 
questions that they might have for the witnesses.
    And this hearing is now adjourned. Thank you.
    [Whereupon, at 2:50 p.m., the Subcommittee was adjourned.]































                              Appendix 1:

                              ----------                              


                   Answers to Post-Hearing Questions




                   Answers to Post-Hearing Questions
Responses by Carl O. Bauer, Director, National Energy Technology 
        Laboratory, U.S. Department of Energy

Questions submitted by Chairman Nick Lampson

Q1.  Because the existing fleet of coal-fired power plants generate 
over 50 percent of the Nation's electricity and are one of the major 
emitters of greenhouse gases and other pollutants like mercury, how 
much funding will be dedicated to retrofitting the existing fleet to 
operate more cleanly and more efficiently in Fiscal Year 2008? How does 
this amount compare to the funds allocated to develop more efficient 
technologies for coal generating power plants in Fiscal Year 2007? 
Could you please elaborate on the specific efficiency retrofitting 
projects prioritized by the Department of Energy?

A1. The Innovations for Existing Plants (IEP) program supported 
technology development for criteria pollutant control technologies 
retrofits to existing conventional power plants, in anticipation of 
regulatory limits that are now being implemented through the Clean Air 
Interstate Rule and the Clean Air Mercury Rule. Because the industry 
now has strong regulatory drivers to complete the development on their 
own and commercially deploy such technologies, the IEP program is 
terminated. However, several programs are funded in the FY 2008 that 
target retrofit technologies for carbon capture, or that target 
technologies for new plants, but are also applicable to retrofit 
applications. In FY 2008, the Department plans to issue a Clean Coal 
Power Initiative (CCPI) Round 3 solicitation that would provide the 
opportunity for proposing projects to retrofit carbon capture 
technology, with ultra low emissions, such as mercury capture, to 
existing plants. However, since the selections require a competitive 
process it is not yet known how much will be awarded for retrofits. In 
FY 2007, the focus of the $414M coal R&D program is on the development 
of cleaner, more efficient technologies for coal generating power 
plants, and carbon sequestration. In each of the years FY 2007 and FY 
2008 approximately $7M is being allocated to Advanced Research 
Materials to improve the efficiency of new and existing plants. The 
carbon sequestration program also funds development of post-combustion 
carbon capture technologies that could be applied as retrofits.

Q2.  A 2007 interdisciplinary MIT Study ``The Future of Coal'' states 
that ``It is critical that the government RD&D program not fall in the 
trap of picking a technology ``winner'' especially at a time when there 
is great coal combustion and conversion development activity underway 
in the private sector in both the United States and abroad.'' IGCC has 
received extensive DOE support through grants and FutureGen funding. 
What is the Department doing to advance oxyfuel technology, given that 
it can be used on all coal types on both existing and new plants and 
could be deployed soon?

A2. DOE does not pick technology winners. Rather, in response to 
environmental drivers such as climate change, the Department's research 
programs provide a portfolio of technology options that could be 
applicable under a variety of future regulatory and/or policy 
scenarios. This allows the marketplace, once regulations have been 
promulgated, to determine the most appropriate technologies for 
commercial deployment, based on performance and cost. Integrated 
gasification combined cycle (IGCC) technology is an important option 
being developed by DOE, applicable to a wide range of coal types. For 
example, the Department's Clean Coal Power Initiative includes a 285 
MWe IGCC project to demonstrate technologies capable of major 
efficiency gains for low-rank, high-moisture, high-ash coals. Oxyfuel 
or oxy-combustion technology also is being investigated and DOE has 
several projects underway in this area.

Q3.  The DOE National Energy Technology Laboratory in Albany, Oregon 
has developed the Integrated Pollutant Removal (IPR) technology. It is 
my understanding that tests show that when coupled with Oxyfuel, the 
hybrid Oxyfuel/IPR system can remove 90 percent of the mercury, 99 
percent of the sulfur, 99 percent of the particulate including 80 
percent of the PM2.5, and NOX measured at the exit of the combustion 
process was 0.088 lbs/MMBtu. I further understand that the Oxyfuel/IPR 
system is also fully capture ready. Please explain any discrepancies 
the Department may have with the information I provided on the IPR 
system.

     When does the Administration anticipate the IPR technology will 
move forward from development to commercial deployment? Will the 
Department need to dedicate additional funding to the IPR technology 
before it is ready for commercial applications? To date, what level of 
funding has been used for the Department's development of the IPR 
technology?

A3. Results from bench-scale development and testing and preliminary 
engineering analyses suggest that the IPR is a promising concept for 
reducing emissions from coal-fired power plants. Based on bench testing 
to date, Albany has achieved NOX combustion levels at the exit of the 
combustion process of 0.088 lb/MMBtu; >99 percent of sulfur were 
removal; and >99 percent removal of particulate matter. However, it 
needs to be stressed that ``bench-scale'' results are not necessarily 
an accurate prediction of commercial results. Coupled with oxyfuel 
combustion to generate a more concentrated CO2 flue gas, the 
IPR concept is one of a number of advanced carbon capture technologies 
being investigated under DOE's research program. As noted in your 
question, NETL's Albany research laboratory has been supporting the 
development of the IPR. Currently, through a Congressionally Directed 
Project, Jupiter Oxygen Corporation has teamed with NETL to integrate 
oxy-combustion with IPR at the Jupiter's test facilities in Hammond, 
Indiana. The timing for commercial deployment of oxyfuel/IPR technology 
is highly uncertain. It will be depend on the results from the Jupiter 
effort, any follow-on pilot and larger field testing over which the DOE 
program has some control; and on other factors outside the control of 
DOE. Finally as with many of the advanced carbon capture technologies 
the private sector also needs to resolve numerous issues before the 
oxyfuel/IPR concept is considered a viable, cost-effective CO2 
mitigation strategy. Because of all these uncertainties it is difficult 
to predict whether the Department will need to dedicate additional 
funding to the IPR technology before it is ready for commercial 
applications. To date, $3 million has been spent for the Department's 
development of the IPR technology.

Q4.  Older natural gas fueled power plants built since 1950 surround 
many cities and contribute to NOX and CO2 pollution. Is it 
possible to retrofit these older gas plants with oxyfuel technology and 
if so, what would be the emissions reductions benefits? If the older 
gas plants were retrofitted with oxyfuel technology what steps would be 
necessary to provide for capture of the CO2? What are the 
cost estimates for adding carbon capture technology to these 
facilities? Is the Department exploring other technologies to reduce 
emissions from gas fueled electric power plants?

A4. It might be possible to retrofit some older natural gas plants with 
oxyfuel technology, and there might be emissions reductions benefits to 
this approach. If gas plants were retrofitted with oxyfuel technology 
the necessary steps would begin with a feasibility study and comparison 
with alternative feasible alternatives. DOE has not performed cost 
estimates for retrofitting older natural gas plants with oxyfuel 
technology. The focus of DOE's carbon capture R&D effort is on 
technology applicable to coal-based power systems. This is because 
coal-fired power plants provide over half of the electricity generated 
in the United States, and their significant contribution to the United 
States' electricity grid is expected to continue through the better 
part of this century. It is recognized, however, that CO2 is 
also emitted from other stationary fossil-fuel-combustion facilities, 
including natural-gas-fired boilers. As such, it is expected that the 
advanced post-combustion carbon capture technologies under development 
as part of DOE's Carbon Sequestration Program will have application to 
natural-gas-fueled power plants. Oxy-combustion is one such technology. 
The technical and operations issues associated with oxyfuel combustion, 
which DOE's R&D program is addressing, would be similar for a gas-fired 
boiler as for a coal-fired boiler. An important technical challenge is 
developing materials to withstand increased temperature in the furnace 
resulting from burning the fuel (coal or natural gas) in an oxygen-rich 
environment.
    Flue gas recirculation is one approach being investigated to reduce 
the temperature, another approach is the development of new materials 
more resistant to high temperatures. Another critical issue associated 
with oxy-combustion is obtaining a large supply of low-cost oxygen. 
Current oxygen production systems, such as cryogenic, are prohibitively 
expensive. This is another area of research under DOE's Carbon 
Sequestration Program.



















                              Appendix 2:

                              ----------                              


                   Additional Material for the Record




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