[Senate Hearing 110-174]
[From the U.S. Government Printing Office]


                                                        S. Hrg. 110-174
 
                         CLEAN COAL TECHNOLOGY 

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




                                HEARING

                               before the

                              COMMITTEE ON
                      ENERGY AND NATURAL RESOURCES
                          UNITED STATES SENATE

                       ONE HUNDRED TENTH CONGRESS

                             FIRST SESSION

                                   TO

    RECEIVE TESTIMONY ON RECENT ADVANCES IN CLEAN COAL TECHNOLOGY, 
     INCLUDING THE PROSPECTS FOR DEPLOYING THESE TECHNOLOGIES AT A 
                  COMMERCIAL SCALE IN THE NEAR FUTURE

                               __________

                             AUGUST 1, 2007


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                COMMITTEE ON ENERGY AND NATURAL RESOURCES

                  JEFF BINGAMAN, New Mexico, Chairman

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

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















                            C O N T E N T S

                              ----------                              

                               STATEMENTS

                                                                   Page

Alix, Frank, Chief Executive Officer, Powerspan, Portsmouth, NH..    55
Barrasso, Hon. John, U.S. Senator From Wyoming...................    30
Bauer, Carl O., Director, National Energy Technology Laboratory, 
  Department of Energy...........................................     2
Bingaman, Hon. Jeff, U.S. Senator From New Mexico................     1
Corker, Hon. Bob, U.S. Senator From Tennessee....................    75
Craig, Hon. Larry E., U.S. Senator From Idaho....................    40
Domenici, Hon. Pete V., U.S. Senator From New Mexico.............    35
Dorgan, Hon. Byron L., U.S. Senator From North Dakota............    38
Fehrman, Bill, President, Pacificorp Energy, Salt Lake City, Utah    64
Hollinden, Jerry, Representative, The National Coal Council, 
  Louisville, KY.................................................    11
Langley, Don C., Vice President and Chief Technology Officer, the 
  Babcock and Wilcox Companies, Barberton, OH....................    46
Perlman, Andrew Chief Executive Officer, Great Point Energy, 
  Cambridge, MA..................................................    49
Phillips, Jeffrey N., Program Manager, Advanced Coal Generation, 
  Electric Power Research, Institute, Charlotte, NC..............    15
Rosborough, Jim, Commercial Director, Alternative Feedstocks, the 
  Dow Chemical Company, Midland, MI..............................    59
Salazar, Hon. Ken, U.S. Senator From Colorado....................    32
Sessions, Hon. Jeff, U.S. Senator From Alabama...................    43
Tester, Hon. Jon, U.S. Senator From Montana......................    45

                                APPENDIX

Responses to additional questions................................    83


                         CLEAN COAL TECHNOLOGY

                              ----------                              


                       WEDNESDAY, AUGUST 1, 2007

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                    Washington, DC.
    The committee met, pursuant to notice, at 9:28 a.m. in room 
SD-366, Dirksen Senate Office Building, Hon. Jeff Bingaman, 
chairman, presiding.

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

    The Chairman. OK, why don't we start the hearing. I'm 
informed Senator Domenici is going to be a little late, but 
that we should proceed without him and he will catch up once he 
gets here.
    Let me just make a few comments, and then we have two 
excellent panels this morning. We'll just start with panel one, 
but let me make these comments first.
    Thank you all very much for coming. We're hoping to learn 
more about the latest advances in clean coal technology as part 
of this hearing. This is a very important subject that the 
committee is spending a lot of time on this year. This is the 
third hearing we've had on coal, so far this year. I think it's 
important that we try to understand the policy, and what the 
right policy should be, with regard to this very important 
resource.
    Coal-fired generation supplies over half, or about half of 
the electricity that we consume in the United States. The 
Energy Information Administration predicts that that share will 
at least stay constant and perhaps even increase over the next 
20 to 30 years. Coal is likely to remain a prominent part of 
our energy supply, both because it's cheap and because it's 
abundant.
    Importantly, it is also true that in other countries, 
particularly the fast-developing countries of India and China. 
They have an unprecedented demand for energy. China, for 
example, has plans to build over 500 new coal-fired power 
plants in the coming years, that we know about. It's estimated 
that a new plant opens there every few weeks, or every week is 
the estimate, every week to ten days.
    If this expansion is accomplished using the sub-critical 
pulverized coal technology that we still use predominantly here 
and throughout the world, the implications for solving our 
global warming problems are serious.
    The United States, largely through the good works of the 
National Laboratories, has been a leader in the development of 
clean coal technology. Over the last few decades technologies 
have been produced and policies have been implemented, to 
significantly reduce emissions of pollutants, such as sulfur 
dioxide and nitrogen oxides and mercury. The next challenge is 
to deal with the issue of carbon dioxide emissions from coal 
generation. Today, those emissions are roughly double the 
emissions produced from burning natural gas.
    We've reached some measure of consensus around the Congress 
that global warming is a problem we need to address. I think 
where we lack consensus is on how to address it. I expect that 
we will be having debates on that subject even before this 
session of the Congress is over. I think what we need to be 
doing in the interim, of course, is determining how we can go 
about reducing emissions and what timeframe we need to follow.
    This latter point of timing is very important, not only 
because of the pace of construction in India and in China that 
I mentioned, but also, when we do arrive at an approach to 
regulating green house gas emissions that puts a price on 
carbon dioxide, we need to try to have technologies identified 
that can be deployed.
    Given a long lead time of five to 10 years between design 
and operation that we have seen for many of these projects, one 
could imagine a scenario where it could be actually decades 
before these technologies would be determined to be 
commercially viable and ready for widespread deployment. So, we 
need to avoid that, if at all possible.
    I hope that in addition to developing these advanced 
technologies, we can collectively come up with some creative 
ways to compress the timeframe for commercial deployment of the 
technologies. I hope some of the testimony today will help us 
with regard to that.
    Let me just introduce the first panel. Carl Bauer, who is 
the Director of the National Energy Technology Laboratory in 
Morgantown, West Virginia is here. Thank you for being here, 
Carl.
    Jerry Hollinden, who is the Senior Vice President of Power 
Business Line, URS Corporation in Louisville, Kentucky. Thank 
you for being here.
    Jeffrey Phillips, who's the Program Manager for Advanced 
Coal Generation with EPRI out of Charlotte, North Carolina. 
Thank you for being here.
    So, why don't you folks go right ahead? Senator Barrasso 
and I will hear your testimony and then have some questions.

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

    Mr. Bauer. Thank you, Mr. Chairman, members of the 
committee. Obviously, with the introduction, Senator, you 
obviously are well-informed, as is the committee, and we thank 
you for your interest.
    Economic prosperity in the United States over the past 
century has relied heavily on the abundance of fossil fuels in 
North America. Making full use of this domestic asset in a 
responsible manner has been, and will be, an essential part of 
how our country fulfills its energy requirements, minimize the 
detrimental environmental impacts, and positively contributes 
to National security and well being.
    Given current technologies, coal prices, and the rates of 
consumption, the United States has approximately a 250-year 
supply of coal available. Coal-fired power plants supply over 
half of our electricity, and are essential to continue to do so 
through at least the mid-century. Several overarching issues 
characterize the current energy situation in the United States: 
environmental quality, energy affordability, and supply 
security. A resolution of these challenges depends in part from 
the development and deployment of technologies that are the 
result of design and implementing a timely and properly tiered 
researched development and demonstration strategy.
    DOE is developing a portfolio of technologies that will 
lead to cost-effective, near-zero atmospheric emissions 
technologies, including green house gases. But both the future 
and existing fleet of coal-based energy plants. The RD&D 
program is divided into a coal R&D program and a demonstration 
component.
    The success of the clean coal R&D will ultimately be judged 
by the extent to which emerging technologies get deployed in 
domestic and international marketplaces. Deploying technologies 
into the international marketplace requires that the 
technologies address environmental and operational performance 
requirements, as well as financial challenges relative to the 
ability of plants to dispatch or sell its electricity at an 
acceptable place in the auction, which characterizes the access 
to the market needed to gain adequate return on investment for 
the utilities.
    This includes, in the regulated market, the ability to 
recover cost in the rate-base, the technical and financial 
risks associated with the deployment of new coal technologies 
are key factors in determining whether they will achieve 
success in the marketplace, and are often difficult to overcome 
for new technologies seeking to make entry.
    In 1985, the Congress authorized DOE to initiate the clean 
coal technology demonstration program to provide additional 
impetus to move technologies from the laboratories to the 
marketplace. This program evolved into the power plant 
improvement initiative and then to the clean coal power 
initiative at present. The purpose of this cost-shared program 
was to develop and demonstrate at commercial scale, innovative 
technologies that would help industry to meet the strict 
environmental requirements, and yet not impinge on the economy 
of the United States.
    More than 20 technologies from the program have achieved 
commercial success in technologies that are related to low-
NOX burners, selective catalytic reduction, flue gas 
desulphurization, fluid-bed combustion, and now mercury. The 
National Research Council estimated that these technologies 
have yielded sales totaling more than $27 billion. 
Announcements of the third solicitation under CCPI is planned 
in this year. The focus is on carbon capture and storage 
technologies. Fossil Energies core R&D program provides for the 
development of new cloth and environmentally effective 
approaches to use coal at predemonstration scale. These include 
advanced research, advanced turbines and hydrogen turbines, 
carbon sequestration and capture, fuel cells gasification, 
hydrogen and fuels production, and innovation for existing 
plants. Details on these programs are in my written testimony. 
Today, nearly three out of every four coal- burning power 
plants in this country, is equipped with technologies that can 
trace their roots back to the clean coal technology program.
    For example, the current generation of low-NOX 
burners alone, is a major clean coal story. Nearly $1.5 billion 
of these burners have been sold and installed. Selective 
catalytic reduction now costs half what it did in the 1980's 
and systems are on order or under construction for 30 percent 
of the coal-fired power plants. Flue gas scrubbers are a third 
of their cost compared to the 1970's and are more reliable, 
less costly, and more efficient. Fluidized- bed technology 
development in the core coal R&D program was first demonstrated 
in that program and has recorded global sales of over $10 
billion. In Tampa, Florida and West Terra Haute, Indiana, the 
first pioneering full-size coal gasification power plants, 
IGCCs, have opened a new pathway for the next generation of 
clean fuel flexible power plants.
    More recently within the coal R&D program, the carbon 
sequestration regional partnerships have brought an enormous 
amount of capability and experience together to work on the 
challenge of both infrastructure development and storing huge 
volumes of CO2 underground permanently. Together 
with DOE, the partnerships secure the active participation of 
more than 500 entities representing more than 350 industrial 
companies, engineering firms, State agencies, non-governmental 
organizations, and other supporting organizations.
    The partnerships are conducting field tests to validate the 
efficacy of carbon capture and storage technologies and a 
variety of geologic and terrestrial storage sites throughout 
the United States and Canada. Extensive data information 
gathered during the initial stages of the project, of the seven 
partnerships, identified the most promising opportunities for 
carbon sequestration in their regions and are performing 25 
geologic field sites and 11 terrestrial field tests.
    In conclusion, DOEs clean coal R&D program has a successful 
track record and a promising future that will ultimately lead 
to pollution-free coal plants.
    Mr. Chairman and members of the committee, this completes 
my statement and I'd be happy to take any questions you have.
    [The prepared statement of Mr. Bauer follows:]

    Prepared Statement of Carl O. Bauer, Director, National Energy 
              Technology Laboratory, Department of Energy
    Thank you Mr. Chairman and Members of the Committee. I appreciate 
this opportunity to provide testimony on the Department of Energy's 
(DOE's) Clean Coal Research and Development (R&D) Program.
    The economic prosperity of the United States over the past century 
has been built upon an abundance of fossil fuels in North America. The 
United States' fossil fuel resources represent a tremendous national 
asset. Making full use of this domestic asset in a responsible manner 
enables the country to fulfill its energy requirements, minimize 
detrimental environmental impacts, and positively contribute to 
national security.
    Given current technologies, coal prices, and rates of consumption, 
the United States has approximately a 250-year supply of coal 
available. Coal-fired power plants supply about half of our electricity 
and are expected to continue to do so through mid-century. Because 
electricity production increases at a rate of about 2% per year, the 
rate of coal use will increase proportionally. However, the continued 
use of this secure domestic resource will be dependent on the 
development of cost-effective technology options to meet both economic 
and environmental goals, including the reduction of greenhouse gas 
emissions.
                 energy issues facing the united states
    Several overarching issues characterize the current energy 
situation in the United States. Their resolution depends in part on 
designing and implementing a timely and properly tailored research, 
development, and demonstration strategy, which could help sustain 
economic growth in the United States. The major issues are energy 
affordability and supply security, and environmental quality.
                energy affordability and supply security
    The availability of affordable energy has been instrumental in 
helping establish the United States' economic engine. The relatively 
recent escalation in energy prices, particularly in oil and natural 
gas, stem, in large measure, from the global competition for these 
energy resources. In particular, as economies in China, India, and 
other countries in the developing world expand to meet the demands of 
their huge populations, their impact on world markets will increase 
through increased competition for oil and gas supplies. Further 
complicating this issue are socio-political and other influences that 
can affect the energy market.
    Despite gains in energy efficiency and projected conservation, 
stemming in part from higher prices, the Energy Information Agency 
(EIA) projects that the U.S. will require increasing amounts of energy 
through 2030, the last year that EIA models. Even after accounting for 
growing contributions from renewable energy and nuclear, our domestic 
coal resources will be required to provide an affordable portion of our 
growing needs.
                         environmental quality
    All fossil fuels incorporate carbon and all contain, to greater or 
lesser degrees, undesirable components, such as sulfur, nitrogen, and 
other trace elements, that can potentially harm the earth's biota.
    It has long been recognized that coal-fired power plants emit 
sulfur and nitrogen containing compounds that combine with the moisture 
in the atmosphere to produce acid rain, and even acid snow. The 
generation of acid rain is not limited to local regions around the 
power plant. These acid forming emissions are often carried over 
hundreds to thousands of miles by wind currents where they are 
deposited to earth through rain or snow. In addition to sulfur and 
nitrogen compounds, coal power plants are also known to emit 
particulates that can, if unmitigated, lead to harmful health effects.
    Air toxics is a term used to describe atmospheric pollutants that, 
if unmitigated, can also cause serious health effects. Air toxics 
include heavy metals, volatile organics, dioxins, and mercury. Relative 
to fossil fuel use, mercury has been the focus of recent attention and 
regulatory action. Mercury health effects are still being investigated 
but have, thus far, been linked to neurological, cardiovascular, and 
respiratory illnesses.
    Currently, there is growing consensus that increased levels of 
greenhouse gases in the atmosphere, primarily carbon dioxide, methane, 
nitrous oxide, and chlorofluorocarbons, are linked to climate change. 
In this connection, fossil fuel use has been identified as a major 
source of anthropogenic greenhouse gas emissions, particularly carbon 
dioxide, into the atmosphere. Slowing the growth of anthropogenic 
greenhouse gas emissions has become an important concern.
    The production of electricity using fossil, nuclear, and renewables 
requires large quantities of water and produces waste byproducts. In 
the United States, thermoelectric power plants utilize more than 130 
billion gallons of water per day. With water supply and availability 
issues becoming more acute across the major growth areas of the United 
States, the energy industry will need to take bold steps to conserve 
water, while meeting all environmental requirements. Coal-fired power 
plants also produce more than 120 million tons of solid waste 
byproducts each year. While 40% of these are re-used in various 
markets, the remainder is deposited into landfills and requires careful 
management and monitoring to prevent harmful environmental impacts.
    Ensuring environmental quality is not a simple matter. 
Environmental requirements are becoming increasingly stringent and 
require new technologies to address the challenges of regulatory 
compliance. The use of fossil fuels is clearly essential for the 
foreseeable future. Therefore, industry, and where appropriate in 
collaboration with the public sector and others, must reduce the 
environmental impact of utilization of these fuels.
                  how is doe responding to the issues
    The Office of Fossil Energy (FE) recognizes the complex energy 
challenges facing America today. Its programs are directly responding 
to the issues laid out above, as well as to the direction provided by 
Congress and the Administration. To ensure a secure energy future for 
the United States, the Nation must commit to energy efficiency and 
renewable energy, but it also must promote the cleaner and more 
productive use of domestic energy resources, including coal, oil, and 
natural gas. The following key thrusts in Fossil Energy's research 
portfolio will lead the way in enhancing energy security from fossil 
fuels.
    Near-Zero Atmospheric Emissions Energy.--DOE is spearheading an R&D 
effort called FutureGen that will utilize technology developments from 
the core R&D program to provide near-zero atmospheric emissions clean 
coal power plants--including carbon capture and sequestration--that 
could ultimately be built at costs comparable to current day 
technology. Together with its supporting technologies for reducing all 
criteria pollutants, FutureGen will help to ensure that coal-fired 
power plants meet the most stringent environmental requirements.
    Climate Change.--DOE conducts R&D that contributes to expanding the 
options for meeting near-term greenhouse gas intensity goals, set by 
President Bush in the Global Climate Change Initiative. By meeting the 
near-term intensity goals, the longer-term goal of atmospheric 
greenhouse gas stabilization will become more achievable. Federal 
investment in climate change mitigation technologies has one overriding 
benefit: a broad suite of such technologies can expand the menu of 
future policy choices, both domestically and internationally. Without 
technology advances, the choice of future greenhouse-gas-reducing 
technologies may be limited to those that are either prohibitively 
expensive or require massive overhauls to existing infrastructure.
                    role of public investment in r&d
    America's fossil fuel industry is a mature industry made up of 
thousands of small companies and major corporations. The strategic role 
of the Federal Government in FE R&D is to develop technology options 
that can benefit the public by addressing market failures. More 
specifically, FE carries out high-risk, high-value R&D that can:

   Accelerate the development of new energy technologies beyond 
        the pace that would otherwise be dictated by normal market or 
        regulatory forces.
   Expand the slate of beneficial energy options beyond those 
        likely to be developed by the private sector on its own.
   Potentially result in revolutionary ``breakthrough'' 
        technologies that achieve environmental, efficiency, and/or 
        cost goals well beyond those currently pursued by the private 
        sector.

    The Federal R&D program is working to provide advanced technology 
options that are significantly more effective and affordable than 
today's limited set of fossil energy technologies. The success of this 
activity could not only benefit current power stations but also 
strengthen the technical foundation for the next generation of coal-
fueled power plants--serving to preserve energy diversity and 
strengthen domestic energy security. The Federal presence in this type 
of R&D may also provide scientifically sound data for future 
governmental regulatory and policy decisions.
    Similarly, the current uncertainty regarding future regulation of 
CO2 is not conducive to significant private-sector 
investment in greenhouse gas mitigation technologies. The Federal R&D 
program, therefore, is developing a wide range of potential carbon 
mitigation approaches--such as carbon sequestration--that can be used 
by the private sector for future investment opportunity.
    Every year, DOE conducts a benefit analysis to quantify and 
highlight the significant economic and energy-sector benefits 
attributable to R&D programs. Estimated impacts on oil and gas 
production, oil imports, power generation technology market 
penetration, carbon intensity, and fuel prices are the basis for 
estimating economic, environmental, and energy security benefits from 
FE's R&D programs.
                       private-sector r&d issues
    Within the electric power industry, R&D investments have been 
historically modest. The National Science Foundation estimates utility-
funded R&D at $114 million in 2001. Nationally, the production of 
electricity consumes over 40 quadrillion British thermal units of 
energy a year. Sixty-nine percent of this energy is contributed by 
fossil fuels and coal is the largest single such contributor of all the 
fossil resources. However, over 65% of that potential energy in that 
coal is lost in the process of generation. Thus, the Nation has an 
obvious interest in increasing the efficiency of electricity 
generation, and thereby reducing harmful emissions while allowing the 
continued use of its most abundant fossil resource--coal. The 
regulations of the Clean Air and Water Acts, as well as the goals of 
the Clear Skies Initiative, as embodied in the Clean Air Interstate 
Rule and the Clean Air Mercury Rule, give utilities the incentives to 
provide the necessary level of R&D needed to achieve these goals. Where 
the incentives do not exist, government may have a role.
                         clean coal technology
    DOE's Office of Fossil Energy is devoted to ensuring that the 
Nation can continue to rely on clean, affordable energy from 
traditional fuel resources. This mission is accomplished through a mix 
of internal and external R&D efforts that concentrate the expertise and 
talents of thousands of public- and private-sector scientists, 
engineers, technicians, and other research professionals. The 
Department is developing a portfolio of cost-effective near-zero 
atmospheric emissions technologies, including greenhouse gases, for the 
future fleet of coal-based energy plants. The RD&D Program is divided 
into a demonstration component and a core R&D program.
                         demonstration program
    The success of Clean Coal R&D will ultimately be judged by the 
extent to which emerging technologies get deployed in domestic and 
international marketplaces. The technical and financial risks 
associated with the deployment of new coal technologies are key factors 
determining whether they will achieve success in the marketplace.
    In 1985, the Congress authorized DOE to initiate the Clean Coal 
Technology Demonstration Program to provide additional impetus to move 
technology from the laboratory to the marketplace. The purpose of the 
program was to develop and demonstrate, at commercial scale, a family 
of innovative technologies that would help industry to meet the strict 
environmental requirements that were ultimately contained in the Clean 
Air Act Amendments of 1990. The Program was developed as a Government/
industry cost-shared partnership and DOE's cost share was limited to a 
maximum of 50% of the funding for each participating project.
    The first projects were started in 1987. These projects were 
selected in the first of five rounds of competition. Over the course of 
the program, 34 projects have been completed. The total cost of these 
five rounds was approximately $3.3 billion, with DOE contributing 
approximately $1.3 billion. In 2001, a solicitation for a follow-on to 
the original five rounds was issued. This program was called the Power 
Plant Improvement Initiative (PPII), and it resulted in six projects, 
of which four are finished, one is still active, and one was withdrawn. 
The total value of the five implemented PPII projects was approximately 
$71 million, with DOE contributing approximately $32 million.
    The program that followed PPII is the Clean Coal Power Initiative 
(CCPI). Solicitations issued in 2002 and 2004 resulted in a total of 10 
projects, eight of which are active, one is not yet started, and one 
was withdrawn. The value of the CCPI projects is approximately $2.7 
billion, with the DOE contribution set at $530 million. The CCPI and 
the earlier programs are referred to collectively as the Clean Coal 
Technology Demonstration Program (the Program).
    More than 20 technologies from the Program have achieved commercial 
success in technologies related to low-NOx burners, 
selective catalytic reduction, flue gas desulfurization, and fluidized-
bed combustion. It is difficult to determine how much commercialization 
of these technologies would have happened absent the DOE assistance.
                      future demonstration program
    Announcement of the third solicitation under CCPI is planned in FY 
2007. Its focus is on carbon capture and storage technologies. This 
current round specifically targets advanced coal based systems and 
subsystems that capture or separate carbon dioxide for sequestration or 
for beneficial uses. Round 3 is also open to any coal-based advanced 
carbon capture technologies that result in co-benefits with respect to 
efficiency, environmental, or economic improvements potentially capable 
of achieving CCPI coal technology performance levels specified in Title 
IV of the Energy Policy Act of 2005.
    DOE is interested in demonstrating advanced technologies not 
currently deployed in the marketplace--specifically technologies 
capable of producing electricity alone or in any combination with heat, 
fuels, chemicals, or hydrogen. Prospective projects must, however, 
ensure that coal is used for at least 75% of the fuel energy input to 
the process and that electricity is at least 50% of the energy-
equivalent output from the technology demonstration.
    DOE is currently developing large-scale field tests of geologic 
carbon sequestration, on the order of 1 million metric tons of 
CO2 per year, and is looking for the best way to structure 
the requirements of the current announcement to allow demonstration 
projects under CCPI to integrate with the sequestration field tests.
                         core coal r&d program
    The Office of Fossil Energy's core coal R&D program provides for 
the development of new cost-and environmentally-effective approaches to 
coal use, approaches at pre-demonstration scale. It includes Advanced 
Research, Advanced Turbines, Carbon Sequestration, Fuel Cells, 
Gasification, Hydrogen and Fuels, and Innovations for Existing Plants, 
which are described in more detail below.
                           advanced research
    The Advanced Research Program is a bridge between basic research 
and the development and deployment of innovative systems capable of 
creating highly efficient and environmentally benign power- and energy-
production systems. Research objectives include resolving the 
technology barriers that enable improvements to emerging power systems 
as well as fundamental research on novel technologies that can be 
utilized in clean energy production. The objective of the program is to 
support development of critical enabling technologies to make it 
possible for the line programs to achieve their goals of developing 
advanced, coal-based power systems for affordable, efficient, near-zero 
atmospheric emissions power generation. Example developments include 
high-temperature materials, revolutionary sensors and controls, and 
advanced computing/visualization techniques.
                           advanced turbines
    The Advanced Turbine Program consists of a portfolio of laboratory 
and field R&D projects focused on performance-improvement technologies 
with great potential for increasing efficiency and reducing emissions 
and costs in coal-based applications. The Program focuses on the 
combustion of pure hydrogen fuels in MW-scale turbines greater than 100 
MW size range and the compression of large volumes of CO2. 
Since advanced turbines will be fuel flexible, capable of operating on 
hydrogen or syngas, they will make possible electric power generation 
in gasification applications configured to capture CO2.
                          carbon sequestration
    The Carbon Sequestration Program consists of a portfolio of 
laboratory and field R&D focused on technologies with great potential 
for reducing greenhouse gas emissions. Most efforts focus on capturing 
carbon dioxide from large stationary sources such as power plants, and 
sequestering carbon dioxide in geologic formations. The Program also 
addresses the control of fugitive methane emissions, which is another 
potent greenhouse gas. Carbon sequestration is a key component of the 
President's strategy to slow the growth of greenhouse gas emissions, as 
well as several National Energy Policy goals targeting the development 
of new technologies. It also supports the goals of the Framework 
Convention on Climate Change and other international collaborations to 
reduce greenhouse gas intensity and greenhouse gas emissions. The 
programmatic timeline is to demonstrate a portfolio of safe, cost-
effective greenhouse gas capture, storage, and mitigation technologies 
at the pre-commercial scale by 2012, leading to demonstration and 
substantial deployment and market penetration beyond 2012. These 
greenhouse gas mitigation technologies could help slow greenhouse gas 
emissions in the medium term. They also provide potential for 
ultimately stabilizing and reducing greenhouse gas emissions in the 
United States.
                               fuel cells
    Fuel cells could help support the efficiency and emission targets 
of future power plants, such as FutureGen. The 50% higher heating value 
target is challenging, and fuel cells can clearly facilitate achieving 
this target when used as the main power block, possibly in combination 
with a turbine. In order to ensure the ability to site future power 
plants in any state in the country, low emissions of criteria 
pollutants will be required. Fuel cell emissions are well below current 
and proposed environmental limits. Fuel cells could play a significant 
part in energy security. Their modular nature permits use in central or 
distributed generation with equal ease. Rapid response to emergent 
energy needs is enhanced by the modularity and fuel flexibility of fuel 
cells. The ultimate goal of the program is the development of low-cost 
large (>100 MW) fuel cell power systems that will produce affordable, 
efficient, and environmentally friendly electrical power from coal with 
greater than 50% higher heating value (HHV) efficiency, including 
integrated coal gasification and carbon dioxide separation processes 
and capture at least 90% of the CO2 emissions from the system. The cost 
goal for fuel cells in coal systems is to achieve a ten-fold reduction 
in the fuel cell system cost.
                               futuregen
    FutureGen is a $1 billion Government-industry initiative to design, 
build, and operate an advanced, coal-based, Integrated Gasification 
Combined-Cycle (IGCC) power plant to:

   Co-produce electricity and hydrogen;
   Achieve near-zero atmospheric emissions, with geological 
        sequestration of carbon dioxide;
   Demonstrate system integration of cutting edge technologies; 
        and
   Chart a technological pathway toward an energy future in 
        which near-zero atmospheric emissions clean coal power plants 
        can be designed, built, and operated at a cost that is no more 
        than 10% above the cost of non-sequestered systems.

    Coal continues to face environmental challenges relative to other 
energy sources. The near-zero atmospheric emissions concept spearheaded 
by FutureGen is vital to the future viability of coal as an energy 
resource, particularly in light of growing climate change concerns. 
Coal is abundant, secure, and relatively inexpensive when compared to 
other energy sources. With near-zero atmospheric emissions, coal could 
not only produce baseload electricity, but also help germinate a 
hydrogen energy economy.
                              gasification
    Gasification is a pre-combustion pathway to convert coal or other 
carbon-containing feedstocks into synthesis gas, a mixture composed 
primarily of carbon monoxide and hydrogen; the synthesis gas, in turn, 
can be used as a fuel to generate electricity or steam, or as a basic 
raw material to produce hydrogen, high-value chemicals, and liquid 
transportation fuels. DOE isdeveloping advanced gasification 
technologies to meet the most stringent environmental regulations in 
any state and facilitate the efficient capture of CO2 for 
subsequent sequestration--a pathway to ``near-zero atmospheric 
emissions'' coal-based energy. Gasification plants are complex systems 
that rely on a large number of interconnected processes and 
technologies. Advances in the current state-of-the-art, as well as 
development of novel approaches, could help reveal the technical 
pathways enabling gasification to meet the demands of future markets 
while contributing to energy security.
                           hydrogen and fuels
    DOE developed the Hydrogen Posture Plan to integrate and implement 
the technology needed to achieve the Hydrogen Economy. The Hydrogen 
from Coal Program was initiated in fiscal year 2004 to support the 
President's Hydrogen Fuel Initiative, DOE's goals in the Hydrogen 
Posture Plan, and the FutureGen project. The mission of the Hydrogen 
from Coal Program is to develop advanced technologies through joint 
public and private RD&D to facilitate the transition to the hydrogen 
economy through central production of gaseous hydrogen.
                    innovations for existing plants
    Over the past three decades, the existing fleet of coal-fired power 
plants has made significant strides in reducing air emissions, 
minimizing impacts on water quality and availability, and managing 
solid byproducts. As the coal-based electric utility sector enters the 
21st century, it will be faced with additional environmental issues 
such as mercury, nitrogen oxide, air toxics, and acid-gas emissions 
control requirements, constraints on water availability needed for 
plant cooling and other purposes, and decreasing space available to 
dispose of the solid residues from coal combustion. The Innovations for 
Existing Plants subprogram supported technology development in 
anticipation of regulatory limits that are now being implemented 
through the Clean Air Interstate Rule and the Clean Air Mercury Rule. 
These rules were promulgated in 2005, giving the private sector an 
incentive to develop the technologies required to reduce their 
pollutant emissions. Because the government role in development of 
these technologies has shifted to the private sector, the Innovations 
for Existing Plants subprogram is no longer needed.
                               conclusion
    Today, nearly three out of every four coal-burning power plants in 
this country are equipped with technologies that can trace their roots 
back to the Clean Coal Technology Program. Approaches demonstrated 
through the program include coal processing to produce clean fuels, 
combustion modification to control emissions, post-combustion cleanup 
of flue gas, and repowering with advanced power generation systems. 
These efforts helped accelerate production of cost-effective compliance 
options to address environmental issues associated with coal use. 
Relative to carbon capture and storage, DOE is making significant 
progress in developing the technologies and infrastructure needed for 
deployment of these technologies in a future carbon-constrained world. 
The following are some examples of clean coal successes that were 
developed in part with DOE support:

   The current generation of low-NOX burners alone 
        is a major clean coal success story. Nearly $1.5 billion of 
        these burners have been sold. Selective catalytic reduction now 
        costs half what it did in the 1980s and systems are on order or 
        under construction for 30 percent of U.S. coal-fired plants.
   Flue gas scrubbers are a third of their cost in the 1970s, 
        and they are more reliable, less costly and more efficient due 
        to innovations developed and tested in Clean Coal Technology 
        Program.
   Fluidized bed technology developed in the core coal R&D 
        program and first demonstrated in the program has recorded 
        global sales of over $10 billion.
   In Tampa, Florida, and West Terre Haute, Indiana, the first 
        pioneering, full-size coal gasification power plants have 
        opened a new pathway for the next generation of clean, fuel-
        flexible power plants. This was made possible through 
        demonstration projects under the Clean Coal Technology Program.
   A number of the commercial demonstration projects have 
        received technology achievement awards. These include the Tidd 
        pressurized fluidized-bed combustion project by Ohio Power 
        Company; Babcock & Wilcox Company low-NOx/cell burner project; 
        Pure Air Lake's advanced flue gas desulfurization project; and 
        Southern Company Services' CT-121 flue gas desulfurization 
        project.
   Advanced coal preparation work previously conducted at 
        NETL's onsite research facilities is now standard practice in 
        the energy industry in achieving product quality specifications 
        for sulfur emissions compliance, as well as reductions of other 
        air pollutants including mercury and other trace elements.
   Work sponsored by the clean coal program continues to look 
        at mercury and multi-pollutant controls for coal-fired boilers. 
        Operation of the TOXECONTM process, which could 
        offer coal-fired power plants a low-cost retrofit option for 
        reducing mercury emissions by up to 90%, was initiated at the 
        We Energies Presque Isle Power Plant in Marquette, Michigan. 
        This project demonstrates the first full-scale commercial 
        mercuryemission-control system for permanent operation.
   The Carbon Sequestration Atlas of the United States and 
        Canada, developed by NETL, the Regional Carbon Sequestration 
        Partnerships (Partnerships), and the National Carbon 
        Sequestration Database and Geographical Information System, 
        contains information on stationary sources for CO2 
        emissions, geologic formations with sequestration potential, 
        and terrestrial ecosystems with potential for enhanced carbon 
        uptake, all referenced to their geographic location to enable 
        matching sources and sequestration sites.
   CO2 capture technology is being developed for 
        solvent, sorbent, membrane, and oxycombustion systems that, if 
        successfully developed, would be capable of capturing greater 
        than 90 percent of the flue gas CO2 at a significant 
        cost reduction when compared to state-of-the-art, amine-based 
        capture systems. Research and systems analysis have identified 
        potential cost reductions of 30-45% for the capture of 
        CO2. In addition, ionic liquid membranes and 
        absorbents are being developed for capture of CO2 
        from power plants. Ionic liquid membranes have been developed 
        at NETL for pre-combustion applications that surpass polymers 
        in terms of CO2 selectivity and permeability at elevated 
        temperatures.
   Field projects have demonstrated the ability to ``map'' 
        CO2 injected into an underground formation at a much 
        higher resolution than previously anticipated and confirmed the 
        ability of perfluorocarbon tracers to track CO2 
        movement through a reservoir. DOE-sponsored research has also 
        led to the development of the U-Tube sampler, which was 
        developed for and successfully deployed at the Frio test site 
        in Texas. This novel tool is used to obtain geochemical samples 
        of both the water and gas portions of downhole samples at in 
        situ pressure.
   The Carbon Sequestration Regional Partnerships have brought 
        an enormous amount of capability and experience together to 
        work on the challenge of infrastructure development. Together 
        with DOE, the Partnerships secured the active participation of 
        more than 500 individuals representing more than 350 industrial 
        companies, engineering firms, state agencies, non-governmental 
        organizations, and other supporting organizations.
   The Partnerships are conducting field tests to validate the 
        efficacy of carbon capture and storage technologies in a 
        variety of geologic storage sites throughout the U.S. and 
        Canada. Using the extensive data and information gathered 
        during the initial stages of the project, the seven 
        Partnerships identified the most promising opportunities for 
        carbon sequestration in their Regions and are performing 25 
        geologic field tests.

    In conclusion, DOE's Clean Coal R&D Program has a successful track 
record and a promising future that will ultimately lead to coal plants 
with near-zero atmospheric emissions.
    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.

    The Chairman. OK, thank you very much.
    Mr. Hollinden, why don't you go right ahead, please.

STATEMENT OF JERRY HOLLINDEN, REPRESENTATIVE, THE NATIONAL COAL 
                            COUNCIL

    Mr. Hollinden. Good morning, Mr. Chairman. My name is Jerry 
Hollinden and today I'm testifying on behalf of the National 
Coal Council.
    The Council is a Federal Advisory Committee to the 
Secretary of Energy. Council membership is by personal 
appointment of the Secretary and included representatives from 
across the broad spectrum of the coal and energy industry. All 
members volunteer their time and expertise to the Secretary on 
issues that he requests the Council to address.
    By letter dated June 26, 2006, Secretary Bodman requested 
that the Council conduct a study of technologies available to 
avoid or capture and store carbon dioxide emissions, especially 
those from coal-fired power plants. Additionally the Secretary 
requested that the Council recommend a technology-base 
framework for mitigating green house gas emissions from those 
plants.
    The Council accepted the Secretary's request, formulated a 
work-group of about 45 experts in the field, and on June 7 of 
this year submitted their report to Secretary Bodman.
    Today, I will summarize the key findings and 
recommendations of that study and I have attached a copy of the 
full report to my testimony for the record.
    The report includes four major findings. One, coal must 
continue its vital and growing role in energy production in the 
United States, supplying more than 50 percent of the Nation's 
electricity. Two, reducing carbon dioxide emissions presents a 
significant technological challenge, but the coal industry has 
a proven record of successfully meeting such challenges and 
stands ready to meet this one as well. Three, it is imperative 
that research, development, and demonstration efforts move 
forward quickly on a portfolio of technologies to reduce our 
capture and store carbon dioxide emissions. Four, public/
private support for technologies to reduce our capture and 
store carbon dioxide is critical to the energy independence and 
security of the United States.
    As indicated by today's hearings, the Council understands 
that Congress intends to address carbon management. In that 
context, it is imperative that the Nation immediately 
accelerate deployment of technologically and economically 
favorable high-efficiency advanced coal combustion, coal 
liquefaction, and gasification technologies. In addition, it is 
critical to accelerate development, demonstration, and 
deployment of carbon dioxide reduction and carbon capture and 
storage technologies to control and sequester carbon dioxide 
emissions from these advanced coal-based technologies.
    With this in mind, the Council made the following 
recommendations to Secretary Bodman. One, work closely with 
other appropriate agencies within the Federal Government to 
streamline--not eliminate as some have accused the Council of 
recommending--but streamlining the long, costly, and 
complicated permitting process for siting, building, and 
operating coal power plants and associated carbon dioxide 
capture, storage, and facilities.
    Two, significantly increase funding across the full 
spectrum of carbon capture and storage technologies, including 
the capture, compression, transportation, storage, and 
monitoring, so as to ensure that the expectations for carbon 
dioxide capture and storage will be met on the local, State, 
and national levels.
    Three, determine the legal liabilities associated with 
carbon capture and storage.
    Four, increase funding of the regional carbon sequestration 
partnerships to adequately finance large- scale carbon dioxide 
storage projects in a number of different geological 
formations, such as deep saline reservoirs.
    Five, support research projects that cover a wide variety 
of capture technologies, including those that capture less than 
90 percent of emissions, because they are in the early stages 
of a technology maturation process.
    Six, pursue a large-scale demonstration project to spur 
development of ultra-supercritical pulverized coal technology 
for electricity generation.
    Seven, ensure Integrated Gasification Combined Cycle 
technology has been completely and efficiently integrated into 
a large-scale power plant and carbon capture and storage 
system.
    As I stated earlier, the Secretary also asked the Council 
to recommend a framework for doing this. To do this, necessary 
actions would be. In the near-term, efficiency improvements at 
existing power plants should be expedited. For the mid-term, 
advanced clean coal technology, such as IGCC and ultra-
supercritical combustion, must be given public support in the 
form of cost and permitting incentives and financial support 
for initial demonstrations so that they can succeed in the 
marketplace. In the long-term, technology for carbon capture 
and storage, including storage sites and related 
infrastructure, must be developed and demonstrated over the 
next 10 years.
    Thank you, Mr. Chairman. I will be happy to answer any 
questions you or the committee members may have.
    [The prepared statement of Mr. Hollinden follows:]

  Prepared Statement of Jerry Hollinden, Representative, The National 
                              Coal Council
    Good morning, Mr. Chairman. My name is Jerry Hollinden and today I 
am testifying on behalf of The National Coal Council. The Council is a 
federal advisory committee to the Secretary of Energy. Council 
membership is by personal appointment of the Secretary and includes 
representatives from across the broad spectrum of the coal and energy 
industry. Council members include senior executives from coal 
producers, shippers and users as well as consultants, conservation 
groups, Native Americans, university faculty members, State government 
officials, lawyers, boiler manufacturers, architect/engineers and large 
electricity consumers. All members volunteer their time and expertise 
to the Secretary on issues that he requests the Council to address.
    By letter dated June 26, 2006 Secretary Samuel Bodman requested 
that the Council ``conduct a study of technologies available to avoid, 
or capture and store, carbon dioxide emissions--especially those from 
coal-fired power plants.'' Additionally, the Secretary requested that 
the Council recommend ``a technology-based framework for mitigating 
greenhouse gas emissions from those plants.''
    The Council accepted the Secretary's request, formulated a working 
group of about 45 experts in the field, and on June 7, 2007 submitted 
their report to Secretary Bodman.
    Today I will summarize the key findings and recommendations of that 
study, and I have attached a copy of the full report* to my testimony 
for the record.
---------------------------------------------------------------------------
    * Document has been retained in committee files.
---------------------------------------------------------------------------
    The report includes four major findings:

          1. Coal must continue its vital and growing role in energy 
        production in the United States, supplying more than 50 percent 
        of the nation's electricity.
          2. Reducing carbon dioxide emissions presents a significant 
        technological challenge, but the coal industry has a proven 
        record of successfully meeting such challenges and stands ready 
        to meet this one as well.
          3. It is imperative that research, development and 
        demonstration efforts move forward quickly on a portfolio of 
        technologies to reduce or capture and store carbon dioxide 
        emissions.
          4. Public-private support for technologies to reduce or 
        capture and store carbon dioxide is critical to the energy 
        independence and security of the United States.

    As indicated by today's hearing, the Council understands that 
Congress intends to address carbon management. In that context, it is 
imperative that the nation immediately accelerate deployment of 
technologically and economically favorable high-efficiency advanced 
coal combustion, coal liquefaction and gasification technologies. In 
addition, it is critical to accelerate development, demonstration and 
deployment of carbon dioxide reduction and carbon capture and storage 
technologies to control and sequester carbon dioxide emissions from 
these advanced coal-based technologies. These technologies will be 
implemented as they become available, affordable and deployable.
    With this in mind the Council made the following recommendations to 
Secretary Bodman. The Department of Energy, acting in coordination with 
other federal agencies and states, should:

          1. Work closely with other appropriate agencies within the 
        federal government to streamline the long, costly and 
        complicated permitting process for siting, building and 
        operating power plants and associated carbon dioxide capture, 
        transportation and storage facilities. Please note that the 
        recommendation is to ``streamline'' this process, not eliminate 
        it, as some have accused the Council of recommending. A 
        cooperative approach by DOE and EPA on rules such as New Source 
        Review, the Clean Air Interstate Rule and the Clean Air Mercury 
        Rule, for example, would be extremely helpful.
          2. Significantly increase funding across the full spectrum of 
        carbon capture and storage technologies--including capture, 
        compression, transportation, storage and monitoring--so as to 
        ensure that the expectations for carbon dioxide capture and 
        storage will be met on the local, state and national levels.
          3. Create a team to lead an engineering program for testing 
        multiple carbon management and storage technologies at power 
        plant scale within the next five years.
          4. Determine the legal liabilities associate with carbon 
        capture and storage. This includes resolving ownership issues 
        and responsibility for stored carbon dioxide in the event of 
        leakage, and implementing long-term monitoring of storage 
        facilities.
          5. Increase funding of the Regional Carbon Sequestration 
        Partnerships to adequately finance large-scale carbon dioxide 
        storage projects in a number of different geologic formations, 
        such as deep saline reservoirs and enhanced coal bed methane 
        recovery. Current projects are focused strongly on enhanced oil 
        recovery applications which enable lower total cost, but 
        further work needs to be done to prove the viability of other 
        kinds of projects so as to represent a spectrum of geology in 
        areas where carbon dioxide is generated.
          6. Support research projects that cover a wide variety of 
        capture technologies, including those that capture less than 90 
        percent of the emissions because they are in the early stages 
        of the technology maturation process. Carbon capture rates will 
        increase as these technologies mature, and these technologies 
        should not be abandoned today simply because they cannot 
        immediately meet high capture expectations early in their 
        development cycle.
          7. Pursue a large scale demonstration project to spur 
        development of ultra-supercritical pulverized coal technology 
        for electricity generation. Extremely high temperatures and 
        pressures (1400 degrees F; 5,000 psi) are required to achieve 
        high plant efficiency, which require the development of new 
        alloys and components.
          8. Integrated Gasification Combined Cycle (IGCC) technology 
        has not been completely and efficiently integrated into a 
        large-scale power plant and carbon capture and storage system. 
        Significantly more work will be required to do this. While this 
        technology is considered commercially available in the chemical 
        industry, the carbon dioxide capture process and acid gas clean 
        up systems being designed for large scale deployment in power 
        plants still constitutes a first-generation application.
          9. Promote significant additional research and demonstration 
        projects related to the transportation and safe storage of 
        carbon dioxide. This would include:

                  a. Developing accepted performance standards or 
                prescriptive design standards for the permanent 
                geological storage of carbon dioxide.
                  b. Fostering the creation of uniform guidelines for 
                site selection, operations, monitoring and closure of 
                storage facilities.
                  c. Ensuring creation of a federal entity to take 
                title to, and responsibility for, long-term post-
                closure monitoring of underground storage, liability 
                and remediation at all carbon dioxide management sites.
                  d. Facilitating development of an economic, efficient 
                and adequate infrastructure for transportation and 
                storage of captured carbon dioxide.
                  e. Creating a legal framework to indemnify all 
                entities that safely capture, transport and store 
                carbon dioxide.
                  f. Creating clear transportation and storage rules 
                that provide incentives to business models that will 
                encourage the development of independent collection 
                pipelines and storage facilities.

          10. Consider undertaking 3-5 projects at a scale of about 1 
        million tons per year of carbon dioxide injection to understand 
        the outstanding technical challenges and to demonstrate to the 
        public that long-term carbon dioxide storage can be achieved 
        safely and effectively.

    As I stated earlier, the Secretary also asked the Council to 
recommend a framework for mitigating greenhouse gas emissions from 
coal-based generating plants. This framework is simple conceptually but 
difficult in terms of marshalling the requisite financial commitments, 
resolving legal and regulatory uncertainties, and instituting 
appropriate risk-sharing mechanisms. Necessary actions include:

    Near Term.--Efficiency improvements at existing plants should be 
expedited. This can be achieved both technically and economically, but 
regulatory barriers must be addressed including the New Source Review 
process. In such cases, New Source Review should not be required for 
plant efficiency improvements that reduce carbon dioxide emissions with 
no subsequent increase in sulfur dioxide or oxides of nitrogen 
emissions increases.
    Mid Term.--Advanced clean coal technologies such as IGCC and ultra-
supercritical combustion must be given public policy support in the 
form of cost and permitting incentives and financial support for 
initial demonstrations so they can succeed in the marketplace. Legal 
questions about liability for long term storage must be addressed. 
Continued progress on FutureGen will be very important in these 
matters.
    Long Term.--Technology for carbon capture and storage, including 
storage sites and related infrastructure, must be developed and 
demonstrated over the next 10 years. Several major carbon capture and 
storage projects must be started as soon as possible in order to 
achieve commercialization within the next 15 years. Oxygen firing 
technologies are designed specifically for carbon capture and will not 
develop independently of storage and infrastructure.

    Ideally, all of this will be done in the context of public-private 
partnerships to more quickly bring these technologies to a state of 
commercial deployment.
    Within 15 years, a suite of carbon capture technologies and storage 
facilities must become commercially available and affordable. When that 
happens, the coal-based electricity generation industry will be able to 
build these technologies into new plants and retrofit them at existing 
plants, where appropriate. In the long run, when these technologies 
become available in the marketplace, other nations using coal can also 
access them at a more reasonable cost.
    Thank you, Mr. Chairman. I will be happy to answer any questions 
you or other Committee members may have.

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

  STATEMENT OF JEFFREY N. PHILLIPS, PROGRAM MANAGER, ADVANCED 
COAL GENERATION, ELECTRIC POWER RESEARCH INSTITUTE, CHARLOTTE, 
                               NC

    Mr. Phillips. Mr. Chairman, I'd like to thank you and your 
colleagues for inviting me to speak to you on behalf of our 
institute. As you can imagine, it's a little difficult to cover 
all the contents of our report in 5 minutes.
    So I just want to give you the highlights, which are, we 
have some good news and some bad news. We also have some more 
good news and some more bad news, and we have some additional 
bad news. So, if you're keeping track, it's two good and three 
bad. But the game is not over yet, and with a concerted public/
private partnership, we believe that the outcome for coal and 
the carbon-constrained future can still be positive.
    Now, the first good news is that any new coal plant built 
today has the capability to achieve extremely low emissions of 
the so-called criteria pollutants--NOX, 
SOx, and so forth--while also operating at a 
significantly higher efficiencies than the existing coal plants 
in the United States.
    Now, most of the coal plants we have here were built in the 
1950s, 1960s, and 1970s and a lot of folks think that coal 
power is old technology and can't be improved. We've been 
building automobiles since the early 1900s and automotive 
technology is still improving. Similarly, today's new coal 
plants are as different from those built 30 years ago as 2007 
electric hybrid car is from a 1975 AMC Pacer. I would have said 
Gremlin, which is what I grew up with, but I think Pacer is 
more humorous.
    While the higher efficiency of today's new plants means 
that they will produce less CO2 per megawatt-hour 
than the existing fleet, our analysis of the electric power 
sector shows that in order to get the sector CO2 
emissions back down to 1990 levels by 2030, it's going to take 
more than just building more efficient coal plants.
    That's where my first bad news comes in. While several 
technologies that can capture CO2 emissions from 
coal power plants are ready to be demonstrated today, our 
analysis shows that they will significantly increase the cost 
of electricity. Capturing 90 percent of the CO2 from 
either a pulverized coal, or an IGCC power plant increases the 
cost of power by up to 80 percent.
    So adding CO2 capture would greatly increase the 
operating cost of a plant well above that of one that doesn't 
capture CO2. This means that a plant with 
CO2 capture will fall down the dispatch order and it 
will reduce the amount of time that that plant is called on to 
operate and consequently, it will reduce the amount of 
CO2 that's actually captured. So some means to 
induce CO2 capture without economically penalizing 
the owner of the power plant needs to be devised. If not, 
CO2 capture technology of any type will not be fully 
utilized.
    My other good news is, that while the impact of capturing 
CO2 today is significant, we have identified R&D 
pathways for both pulverized coal and IGCC that could 
dramatically reduce the cost of CO2 capture. The 
Joint Kirk-EPRI Roadmap issued last year, shows that with 
appropriate R&D and demonstrations, technology for 
CO2 capturing coal plants built in 2025 could lead 
to only a 10 percent increase in the cost of electricity.
    The other bad news is, that at current levels of funding 
for coal R&D, we'll never get there by 2025. In fact, we might 
not even get there by 2045. Getting a broad portfolio of cost-
effective capture technologies will require substantially 
increased--although not unprecedented--investments in R&D from 
both government and industry, on an unwavering basis over the 
next 20 plus years. Now toward this end, EPRI is now developing 
and marshalling support for an ambitious set of industry-led 
projects to address the R&D challenge.
    Now, I want to emphasize that whenever you try out new 
technologies, you're bound to run into glitches and reliability 
is going to suffer. Consequently, we recommend following a 
``walk before you run'' strategy, which means we'll try out 
these systems on a few plants, perhaps not at full scale to 
limit the cost. Let us fall on our bottoms a few times, dust 
ourselves off, figure out what went wrong, get the kinks out, 
before we start widespread deployment.
    My final bad news is that even if we were able to drive the 
cost of capturing CO2 to zero tomorrow, it's highly 
unlikely that any power plant owner will inject CO2 
into deep reservoirs given the current uncertainty over the 
regulations and liability of deep geologic storage of 
CO2.
    Now, I'm confident that our nation's engineers and 
scientists can solve the challenge of capturing CO2 
at economically acceptable costs, but we need help from you on 
the legal issues.
    So in summary, today's new coal power plants are cleaner 
and more efficient than the existing fleet. Today's 
CO2 capture technology will increase wholesale 
electricity prices by up to 80 percent, but we've identified a 
clear technology pathway that could decrease that to only 10 
percent by 2025. Unfortunately, the funding for the development 
of that path is sadly inadequate. Finally, we engineers need 
some legal experts to help us sort out the rules for deep 
geologic storage of CO2.
    Thank you and I'll be happy to take your questions.
    [The prepared statement of Mr. Phillips follows:]

  Prepared Statement of Jeffrey N. Phillips, Ph.D., Program Manager, 
     Advanced Coal Generation, Electric Power Research Institute, 
                             Charlotte, NC
                              introduction
    I am Jeff Phillips, Program Manager for Advanced Coal Generation 
for the Electric Power Research Institute (EPRI). EPRI is a non-profit, 
collaborative R&D organization with principal offices in Palo Alto, 
California, and Charlotte, North Carolina, where I work. EPRI 
appreciates the opportunity to provide testimony to the Subcommittee on 
the topic of carbon capture and sequestration.
                               background
    Coal is the energy source for half of the electricity generated in 
the United States. Even with the aggressive development and deployment 
of alternative energy sources, numerous forecasts of energy use predict 
that coal will continue to provide a major share of our electric power 
generation throughout the 21st century. Coal is a stably priced, 
affordable, domestic fuel that can be used in an environmentally 
responsible manner. Criteria air pollutants from all types of new coal 
power plants have been reduced by more than 90% compared with plants 
built 40 years ago. With the development and deployment of 
CO2 capture and storage (CCS) technologies, coal power 
becomes part of the solution to satisfying both our energy needs and 
our global climate change concerns. However, a sustained RD&D program 
at heightened levels of investment and resolution of legal and 
regulatory unknowns for long-term geologic CO2 storage will 
be required to achieve the promise of clean coal technologies. EPRI 
sees crucial roles for both industry and governments in aggressively 
pursuing collaborative RD&D over the next 20+ years to create a 
portfolio of commercially self-sustaining, competitive advanced coal 
power generation and CO2 capture and storage technologies.
    The potential return on this investment is enormous. EPRI's 
``Electricity Technology in a Carbon-Constrained Future'' study 
suggests that it is technically feasible to reduce U.S. electric sector 
CO2 emissions over the next 25 years while meeting the 
increased demand for electricity, with the largest single contribution 
to emissions reduction coming from application of CCS technologies to 
new coal-based power plants coming on-line after 2020. Economic 
analyses of scenarios to achieve the study's emission reduction goals 
show that a 2030 U.S. energy mix including advanced coal technologies 
with CCS results in electricity at half the cost of a 2030 energy mix 
without coal with CCS. In the case with advanced coal with CCS, the 
U.S. economy is $1 trillion larger than in the case without coal and 
CCS, with a much stronger manufacturing sector. A previous EPRI 
economic study based on financial market ``options'' principles 
produced a similar result, estimating the added cost to U.S. consumers 
through 2050 of not having coal's price-stabilizing influence on the 
electricity system at $1.4 trillion (present value basis).
    The portfolio aspect of advanced coal and CCS technologies must be 
emphasized because no single advanced coal technology (or any 
generating technology) has clear-cut economic advantages across the 
range of U.S. applications. The best strategy for meeting future 
electricity needs while addressing climate change concerns and 
minimizing economic disruption lies in developing multiple technologies 
from which power producers (and their regulators) can choose the option 
best suited to local conditions and preferences. When it comes to CCS 
technology, there is no ``silver bullet,'' but we can develop ``silver 
buckshot.''
    Toward this end, four major technology efforts related to 
CO2 emissions reduction from coal-based power systems must 
be undertaken:

          1. Increased efficiency and reliability of integrated 
        gasification combined cycle (IGCC) power plants.
          2. Increased thermodynamic efficiency of pulverized-coal (PC) 
        power plants.
          3. Improved technologies for capture of CO2 from 
        coal combustion-and gasification-based power plants.
          4. Reliable, acceptable technologies for long-term storage of 
        captured. CO2

    Identification of mechanisms to share RD&D financial and technical 
risks and to address legal and regulatory uncertainties must take place 
as well.
    In short, a comprehensive recognition of all the factors needed to 
hasten deployment of competitive, commercial advanced coal and 
CO2 capture and storage technologies--and implementation of 
realistic, pragmatic plans to overcome barriers--is the key to meeting 
the challenge to supply affordable, environmentally responsible energy 
in a carbon-constrained world.
  accelerating rd&d on advanced coal technologies with co2 
         capture and storage--investment and time requirements
    A typical path to develop a technology to commercial maturity 
consists of moving from the conceptual stage to laboratory testing, to 
small pilot-scale tests, to larger-scale tests, to multiple full-scale 
demonstrations, and finally to deployment in full-scale commercial 
operations. For capital-intensive technologies such as advanced coal 
power systems, each stage can take years or even decades to complete 
and each sequential stage tends to entail increasing levels of 
investment. As depicted in Figure 1,* several key advanced coal power 
and CCS technologies are now in (or approaching) an ``adolescent'' 
stage of development. This is time of particular vulnerability in the 
technology development cycle, as it is common for the expected costs of 
full-scale application to be higher than earlier estimates when less 
was known about scale-up and application challenges. Public agency and 
private funders can become disillusioned with a technology development 
effort at this point, but as long as fundamental technology performance 
results continue to meet expectations, and a path to cost reduction is 
clear, perseverance by project sponsors in maintaining momentum is 
crucial. Unexpectedly high costs at the mid-stage of technology 
development have historically come down following market introduction, 
experience gained from ``learning-by-doing,'' realization of economies 
of scale in design and production as order volumes rise, and removal of 
contingencies covering uncertainties and first-of-a-kind costs. An 
International Energy Agency study led by Carnegie Mellon University 
observed this pattern in the cost over time of power plant 
environmental controls and has predicted a similar reduction in the 
cost of power plant CO2 capture technologies as the 
cumulative installed capacity grows.\1\ EPRI concurs with their 
expectations of experience-based cost reductions and believes that RD&D 
on specifically identified technology refinements can lead to greater 
cost reductions sooner in the deployment phase.
---------------------------------------------------------------------------
    * Figures 1-12 have been retained in committee files.
    \1\ IEA Greenhouse Gas R&D Programme (IEA GHG), ``Estimating Future 
Trends in the Cost of CO2 Capture Technologies,'' 2006/5, 
January 2006.
---------------------------------------------------------------------------
    Of the coal-based power generating and carbon sequestration 
technologies shown in Figure 1, only supercritical pulverized coal 
(SCPC) technology has reached commercial maturity. It is crucial that 
other technologies in the portfolio--namely ultra-supercritical (USC) 
PC, integrated gasification combined cycle (IGCC), CO2 
capture (pre-combustion, post-combustion, and oxy-combustion), and 
CO2 storage--be given sufficient support to reach the stage 
of declining constant dollar costs before society's requirements for 
greenhouse gas reductions compel their application in large numbers.
    Figure 2* depicts the major activities in each of the four 
technology areas that must take place to achieve a set of robust 
solutions to reduce CO2 emissions from coal power systems. 
This framework should be considered as a whole rather than as a set of 
discrete tasks. Although individual goals related to efficiency, 
CO2 capture, and CO2 storage present major 
challenges, significant challenges also arise from complex interactions 
that occur when CO2 capture processes are integrated with 
gasification-and combustion-based power plant processes.
  reducing co2 emissions through improved coal power plant 
                               efficiency
    Improved thermodynamic efficiency reduces CO2 emissions 
by reducing the amount of fuel required to generate a given amount of 
electricity. A two-percentage point gain in efficiency provides a 
reduction in fuel consumption of roughly 5% and a similar reduction in 
CO2 output. Depending on the technology used, improved 
efficiency can also provide similar reductions in criteria air 
pollutants, hazardous air pollutants, and water consumption.
    A ``typical'' 500 MW (net) coal plant emits about 3 million metric 
tons of CO2 per year. The annual power output and emissions 
of the current U.S. coal fleet are roughly equivalent to 600 such 
plants. The contributions attributable to individual plants vary 
considerably with differences in plant steam cycle, coal type, capacity 
factor, and operating regimes. For a given fuel, a new supercritical PC 
unit built today might produce 5-10% less CO2 per megawatt-
hour (MWh) than the existing fleet average for that coal type.
    With an aggressive RD&D program on efficiency improvement, new 
ultra-supercritical (USC PC) plants could reduce CO2 
emissions per MWh by up to 25% relative to the existing fleet average. 
Significant efficiency gains are also possible for IGCC plants by 
employing advanced gas turbines and through more energy-efficient 
oxygen plants and synthesis (fuel) gas cleanup technologies.
    EPRI and the Coal Utilization Research Council (CURC), in 
consultation with DOE, have identified a challenging but achievable set 
of milestones for improvements in the efficiency, cost, and emissions 
of PC and coal-based IGCC plants. The EPRI-CURC Roadmap projects an 
overall improvement in the thermal efficiency of state-of-the art 
generating technology from 38-41% in 2010 to 44-49% by 2025 (on a 
higher heating value [HHV] basis; see Table 1). The ranges in the 
numbers are not simply a reflection of uncertainty, but rather they 
underscore an important point about differences among U.S. coals. The 
natural variations in moisture and ash content and combustion 
characteristics between coals have a significant impact on efficiency. 
The best efficiencies are possible with bituminous coals, a mid-range 
value is applicable to subbituminous coals, and the low end of the 
range is for lignite. Thus, an equally advanced plant might have a two 
percentage point lower efficiency on subbituminous coal, such as 
Wyoming and Montana's Powder River basin, relative to Pennsylvania and 
West Virginia's Pittsburgh #8. The efficiency for the same plant using 
lignite from North Dakota or Texas might be two percentage points even 
lower than that for subbituminous coal. Any government incentive 
program with an efficiency-based qualification criterion should 
recognize these inherent differences in the attainable efficiencies for 
plants using different ranks of coal.
    As Table 1 indicates, technology-based efficiency gains over time 
will be offset by the energy required for CO2 capture. 
Nevertheless, aggressive pursuit of the EPRI-CURC RD&D program offers 
the prospect of coal plants with CO2 capture in 2025 that 
have net efficiencies meeting or exceeding current-day power plants 
without CO2 capture.

                               Table 1--Efficiency Milestones in EPRI-CURC Roadmap
----------------------------------------------------------------------------------------------------------------
                                                       2010            2015            2020            2025
----------------------------------------------------------------------------------------------------------------
PC & IGCC Systems (Without CO2 Capture)               38-41% HHV      39-43% HHV      42-46% HHV      44-49% HHV
----------------------------------------------------------------------------------------------------------------
PC & IGCC Systems (With CO2 Capture*)                 31-32% HHV      31-35% HHV      33-39% HHV      39-46% HHV
----------------------------------------------------------------------------------------------------------------
* Efficiency values reflect impact of 90% CO2 capture, but not compression or transportation.

                new plant efficiency improvements--igcc
    Although IGCC is not yet a mature technology for coal-fired power 
plants, chemical plants around the world have accumulated a 100-year 
experience base operating coal-based gasification units and related gas 
cleanup processes. The most advanced of these units are similar to the 
front end of a modern IGCC facility. Similarly, several decades of 
experience firing natural gas and petroleum distillate have established 
a high level of maturity for the basic combined cycle generating 
technology. Nonetheless, ongoing RD&D continues to provide significant 
advances in the base technologies, as well as in the suite of 
technologies used to integrate them into an IGCC generating facility.
    Efficiency gains in currently proposed IGCC plants will come from 
the use of new ``FB-class'' gas turbines, which will provide an overall 
plant efficiency gain of about 0.6 percentage point (relative to IGCC 
units with FA-class models, such as Tampa Electric's Polk Power 
Station). This corresponds to a decrease in CO2 emissions 
rate of about 1.5%.
    Figure 3* depicts the anticipated timeframe for further 
developments identified by EPRI's CoalFleet for Tomorrow program that 
promise a succession of significant improvements in IGCC unit 
efficiency. Key technology advances under development include: larger 
capacity gasifiers (often via higher operating pressures that boost 
throughput without a commensurate increase in vessel size); integration 
of new gasifiers with larger, more efficient G- and H-class gas 
turbines; use of ion transport membrane (ITM) and/or other more energy-
efficient technologies in oxygen plants; warm synthesis gas cleanup and 
membrane separation processes for CO2 capture that reduce 
energy losses in these areas; recycle of liquefied CO2 to 
replace water in gasifier feed slurry (reducing heat loss to water 
evaporation); and hybrid combined cycles using fuel cells to achieve 
generating efficiencies exceeding those of conventional combined cycle 
technology. Improvements in gasifier reliability and in control systems 
also contribute to improved annual average efficiency by minimizing the 
number and duration of startups and shutdowns.
    Larger, Higher Firing Temperature Gas Turbines.--For plants coming 
on-line around 2015, the larger size G-class gas turbines, which 
operate at higher firing temperatures (relative to F-class machines) 
can improve efficiency by 1 to 2 percentage points while also 
decreasing capital cost per kW capacity. The H-class gas turbines, 
coming on-line in the same timeframe, will provide a further increase 
in efficiency and capacity.
    Ion Transport Membrane--Based Oxygen Plants.--Most gasifiers used 
in IGCC plants require a large quantity of high-pressure, high purity 
oxygen, which is typically generated on-site with an expensive and 
energy-intensive cryogenic process. The ITM process allows the oxygen 
in high-temperature air to pass through a membrane while preventing 
passage of non-oxygen atoms. According to developers, an ITM-based 
oxygen plant consumes 35-60% less power and costs 35% less than a 
cryogenic plant. EPRI is performing a due diligence assessment of this 
technology in advance of potential participation in technology scale-up 
efforts.
    Supercritical Heat Recovery Steam Generators.--In IGCC plants, hot 
exhaust gas exiting the gas turbine is ducted into a heat exchanger 
known as a heat recovery steam generator (HRSG) to transfer energy into 
water-filled tubes producing steam to drive a steam turbine. This 
combination of a gas turbine and steam turbine power cycles produces 
electricity more efficiently than either a gas turbine or steam turbine 
alone. As with conventional steam power plants, the efficiency of the 
steam cycle in a combined cycle plant increases when turbine inlet 
steam temperature and pressure are increased. The higher exhaust 
temperatures of G-and H-class gas turbines offer the potential for 
adoption of more-efficient supercritical steam cycles. Materials for 
use in a supercritical HRSG are generally established.
    Synthesis Gas Cleaning at Higher Temperatures.--The acid gas 
recovery (AGR) processes currently used to remove sulfur compounds from 
synthesis gas require that the gas and solvent be cooled to about 
100F, thereby causing a loss in efficiency. Further costs and 
efficiency loss are inherent in the process equipment and auxiliary 
steam required to recover the sulfur compounds from the solvent and 
convert them to useable products. Several DOE-sponsored RD&D efforts 
aim to reduce the energy losses and costs imposed by this recovery 
process. These technologies (described below could be ready--with 
adequate RD&D support--by 2020:

   The Selective Catalytic Oxidation of Hydrogen Sulfide 
        process eliminates the Claus and Tail Gas Treating units along 
        with the traditional solvent-based AGR contactor, regenerator, 
        and heat exchangers by directly converting hydrogen sulfide 
        (H2S) to elemental sulfur. The process allows for a 
        higher operating temperature of approximately 300F, which 
        eliminates part of the low-temperature gas cooling train. The 
        anticipated benefit is a net capital cost reduction of about 
        $60/kW along with an efficiency gain of about 0.8 percentage 
        point.
   The RTI/Eastman High Temperature Desulfurization System uses 
        a regenerable dry zinc oxide sorbent in a dual loop transport 
        reactor system to convert H2S and COS to 
        H2O, CO2, and SO2. Tests at 
        Eastman Chemical Company have shown sulfur species removal 
        rates above 99.9%, with 10 ppm output versus 8000+ ppm input 
        sulfur, using operating temperatures of 800-1000F. This 
        process is also being tested for its ability to provide a high-
        pressure CO2 by-product. The anticipated benefit for 
        IGCC, compared with using a standard oil-industry process for 
        sulfur removal, is a net capital cost reduction of $60-90 per 
        kW, a thermal efficiency gain of 2-4% for the gasification 
        process, and a slight reduction in operating cost. Tests are 
        also under way for a multi-contaminant removal processes that 
        can be integrated with the transport desulfurization system at 
        temperatures above 480F.

    Liquid CO2-Coal Slurrying for Gasification of Low-Rank 
Coals.--Future IGCC plants may recycle some of the recovered liquid 
CO2 to replace water as the slurrying medium for the coal 
feed. This is expected to increase gasification efficiency for all 
coals, but particularly for low-rank coals (i.e., subbituminous and 
lignite), which have high inherent moisture content. The liquid 
CO2 has a lower heat of vaporization than water and is able 
to carry more coal per unit mass of fluid. The liquid CO2-
coal slurry will flash almost immediately upon entering the gasifier, 
providing good dispersion of the coal particles and potentially 
yielding dry-fed gasifier performance with slurry-fed simplicity.
    Slurry-fed gasification technologies have a cost advantage over 
conventional dry-fed fuel handling systems, but they suffer a large 
performance penalty when used with coals containing a large fraction of 
water and ash. EPRI identified CO2 coal slurrying as an 
innovative fuel preparation concept 20 years ago, when IGCC technology 
was in its infancy. At that time, however, the cost of producing liquid 
CO2 was too high to justify the improved thermodynamic 
performance.
    To date, CO2-coal slurrying has only been demonstrated 
at pilot scale and has yet to be assessed in feeding coal to a 
gasifier, so the estimated performance benefits remain to be confirmed. 
The concept warrants consideration for future IGCC plants that capture 
and compress CO2 for storage, as this will substantially 
reduce the incremental cost of producing a liquid CO2 
stream. It will first be necessary, however, to update previous studies 
to quantify the potential benefit of liquid CO2 slurries 
with IGCC plants designed for CO2 capture. If the predicted 
benefit is economically advantageous, a significant amount of scale-up 
and demonstration work would be required to qualify this technology for 
commercial use.
    Fuel Cells and IGCC.--No matter how far gasification and turbine 
technology advance, IGCC power plant efficiency will never progress 
beyond the inherent thermodynamic limits of the gas turbine and steam 
turbine power cycles (along with lower limits imposed by available 
materials technology). Several IGCC-fuel cell hybrid power plant 
concepts (IGFC) aim to provide a path to coal-based power generation 
with net efficiencies that exceed those of conventional combined cycle 
generation.
    Along with its high thermal efficiency, the fuel cell hybrid cycle 
reduces the energy consumption for CO2 capture. The anode 
section of the fuel cell produces a stream that is highly concentrated 
in CO2. After removal of water, this stream can be 
compressed for sequestration. The concentrated CO2 stream is 
produced without having to include a water-gas shift reactor in the 
process (see Figure 4*). This further improves the thermal efficiency 
and decreases capital cost. IGFC power systems are a long-term 
solution, however, unlikely to see full-scale demonstration until about 
2030.
    Role of FutureGen.--The FutureGen Industrial Alliance and DOE are 
building a first-of-its-kind, near-zero emissions coal-fed IGCC power 
plant integrated with CCS. The commencement of full-scale operations is 
targeted for 2013. The project aims to sequester CO2 in a 
representative geologic formation at a rate of at least one million 
metric tons per year.
    The FutureGen design will address scaling and integration issues 
for coal-based, zero emissions IGCC plants. In its role as a ``living 
laboratory,'' FutureGen is designed to validate additional advanced 
technologies that offer the promise of clean environmental performance 
at a reduced cost and increased reliability. FutureGen will have the 
flexibility to conduct full-scale and slipstream tests of such scalable 
advanced technologies such as:

   Membrane processes to replace cryogenic separation for 
        oxygen production.
   An advanced transport reactor sidestream with 30% of the 
        capacity of the main gasifier.
   Advanced membrane and solvent processes for H2 
        and CO2 separation.
   A raw gas shift reactor that reduces the upstream clean-up 
        requirements.
   Ultra low-NOX combustors that can be used with 
        high-hydrogen synthesis gas.
   A fuel cell hybrid combined cycle pilot.
   Challenging first-of-a-kind system integration.
   Smart dynamic plant controls including a CO2 
        management system.

    Figure 5* provides a schematic of the ``backbone'' and ``research 
platform'' process trains envisioned for the FutureGen plant.
    Figure 6* summarizes EPRI's recommended major RD&D activities for 
improving the efficiency and cost of IGCC technologies with 
CO2 capture.
      new plant efficiency improvements--advanced pulverized coal
    Pulverized-coal power plants have long been a primary source of 
reliable and affordable power in the United States and around the 
world. The advanced level of maturity of the technology, along with 
basic thermodynamic principles, suggests that significant efficiency 
gains can most readily be realized by increasing the operating 
temperatures and pressures of the steam cycle. Such increases, in turn, 
can be achieved only if there is adequate development of suitable 
materials and new boiler and steam turbine designs that allow use of 
higher steam temperatures and pressures.
    Current state-of-the-art plants use supercritical main steam 
conditions (i.e., temperature and pressure above the ``critical point'' 
where the liquid and vapor phases of water are indistinguishable). SCPC 
plants typically have main steam conditions up to 1100F. The term 
``ultra-supercritical'' is used to describe plants with main steam 
temperatures in excess of 1100F and potentially as high as 1400F.
    Achieving higher steam temperatures and higher efficiency will 
require the development of new corrosion-resistant, high-temperature 
nickel alloys for use in the boiler and steam turbine. In the United 
States, these challenges are being address by the Ultra-Supercritical 
Materials Consortium, a DOE R&D program involving Energy Industries of 
Ohio, EPRI, the Ohio Coal Development Office, and numerous equipment 
suppliers. EPRI provides technical management for the consortium.
    It is expected that a USC PC plant operating at about 1300F will 
be built during the next seven to ten years, following the 
demonstration and commercial availability of advanced materials from 
these programs. This plant would achieve an efficiency of about 45% 
(HHV) on bituminous coal, compared with 39% for a current state-of-the-
art plant, and would reduce CO2 production per net MWh by 
about 15%.
    Ultimately, nickel-base alloys are expected to enable stream 
temperatures in the neighborhood of 1400F and generating efficiencies 
up to 47% HHV with bituminous coal. This approximately 10 percentage 
point improvement over the efficiency of a new subcritical pulverized-
coal plant would equate to a decrease of about 25% in CO2 
and other emissions per MWh.
    Figure 7* illustrates a timeline developed by EPRI's CoalFleet for 
Tomorrow program to establish efficiency improvement and cost 
reduction goals for USC PC plants with CO2 capture.
    UltraGen USC PC Commercial Projects.--EPRI and industry 
representatives have proposed a framework to support commercial 
projects that demonstrate advanced PC technologies. The vision entails 
construction of two commercially operated USC PC power plants that 
combine state-of-the-art pollution controls, ultra-supercritical steam 
power cycles, and innovative flue gas scrubbing technologies to capture 
CO2.
    The UltraGen I plant will use the best of today's proven ferritic 
steels, while UltraGen II will be the first plant in the United States 
to feature new, nickel-based alloys that are able to withstand the 
higher temperatures involved. UltraGen I will feature an approximately 
quarter-scale CO2 capture system demonstration using the 
best established technology. This system will be about 15 times the 
size of the largest system operating on a coal-fired boiler today. 
UltraGen II will double the size of the CO2 capture system, 
and may demonstrate a new class of chemical solvent if one of the 
emerging low-energy processes has reached a sufficient stage of 
development. Both plants will demonstrate ultra-low emissions. Both 
UltraGen demonstration plants will dry and compress the captured 
CO2 for long-term geologic storage and/or use in enhanced 
oil or gas recovery operations. Figure 8* depicts the proposed key 
features of UltraGen I and II.
    To provide a platform for testing and developing emerging PC 
technologies, the program will allow for technology trials at existing 
sites as well as at the sites of new projects. It is expected that the 
UltraGen projects will be commercially operated units dispatching 
electricity to the grid. The differential cost to the host utility for 
demonstrating these improved features are envisioned to be offset by 
tax credits and funds raised by an industry-led consortia formed 
through EPRI.
    The UltraGen projects represent the type of ``giant step'' 
collaborative efforts that need to be taken to advance PC technology to 
the next phase of evolution and assure competitiveness in a carbon-
constrained world. Because of the time and expense for each ``design 
and build'' iteration for coal power plants (3 to 5 years not counting 
the permitting process and $2 billion), there is no room for 
hesitation in terms of commitment to advanced technology validation and 
demonstration projects.
    The UltraGen projects will resolve critical barriers to the 
deployment of USC PC technology by providing a shared-risk vehicle for 
testing and validating high-temperature materials, components, and 
designs in plants also providing superior environmental performance.
    Figure 9* summarizes EPRI's recommended major RD&D activities for 
improving the efficiency and cost of USC PC technologies with 
CO2 capture.
    Efficiency Gains for the Existing PC Fleet.--Many subcritical units 
in the existing U.S. fleet will continue to operate for years to come. 
Replacing these units en masse would be economically prohibitive. Their 
flexibility for load following and provision of support services to 
ensure grid stability makes them highly valuable. With equipment 
upgrades, many of these units can realize modest efficiency gains, 
which, when accumulated across the existing generating fleet could make 
a sizeable difference.
    These upgrades depend on the equipment configuration and operating 
parameters of a particular plant and may include:

   turbine blading and steam path upgrades.
   turbine control valve upgrades for more efficient regulation 
        of steam.
   cooling tower and condenser upgrades to reduce circulating 
        water temperature, steam turbine exhaust backpressure, and 
        auxiliary power consumption.
   cooling tower heat transfer media upgrades.
   condenser optimization to maximize heat transfer and 
        minimize condenser temperature.
   condenser air leakage prevention/detection.
   variable speed drive technology for pump and fan motors to 
        reduce power consumption.
   air heater upgrades to increase heat recovery and reduce 
        leakage.
   advanced control systems incorporating neural nets to 
        optimize temperature, pressure, and flow rates of fuel, air, 
        flue gas, steam, and water.
   optimization of water blowdown and blowdown energy recovery.
   optimization of attemperator design, control, and operating 
        scenarios.
   sootblower optimization via ``intelligent'' sootblower 
        system use.
             improving co2 capture technologies
    The laws of physics and chemistry impose inherent limits on the 
extent of CO2 reductions that can be achieved through 
efficiency gains alone. Further reductions in CO2 emissions 
will require pre-combustion or post-combustion CO2 capture 
technologies and the storage of separated CO2 in locations 
where it can be kept away from the atmosphere for centuries or longer.
    Albeit at considerable cost, CO2 capture technologies 
can be integrated into all coal-based power plant technologies. For 
existing plants, specific plant design features, space limitations, and 
various economic and regulatory considerations will determine whether 
retrofit-for-capture is feasible. For both new plants and retrofits, 
there is a tremendous need (and opportunity) to reduce the energy 
required to remove CO2 from fuel gas or flue gas. Figure 10* 
shows a selection of the key technology development and test programs 
needed to achieve a goal of commercial CO2 capture 
technologies for advanced coal combustion-and gasification-based power 
plants at a progressively shrinking constant-dollar levelized cost-of-
electricity premium. Specifically, the target is premium of about $6/
MWh in 2025 (relative to plants at that time without capture) compared 
with an estimated 2010 cost premium of perhaps $40/MWh (not counting 
the cost of transportation and storage). Such a goal poses substantial 
engineering challenges and will require major investments in RD&D to 
reduce the currently large net power reductions and efficiency 
(operating cost) penalties associated with CO2 capture 
technologies. Achieving this goal will allow power producers to meet 
the public demand for stable electricity prices while reducing 
CO2 emissions to address climate change concerns.
              pre-combustion co2 capture (igcc)
    IGCC technology allows for CO2 capture to take place via 
an added fuel gas processing step at elevated pressure, rather than at 
the atmospheric pressure of post-combustion flue gas, permitting 
capital savings through smaller equipment sizes as well as lower 
operating costs.
    Currently available technologies for such pre-combustion 
CO2 removal use a chemical and/or physical solvent that 
selectively absorbs CO2 and other ``acid gases,'' such as 
hydrogen sulfide. Application of this technology requires that the CO 
in synthesis gas (the principal component) first be ``shifted'' to 
CO2 and hydrogen via a catalytic reaction with water. The 
CO2 in the shifted synthesis gas is then removed via contact 
with the solvent in an absorber column, leaving a hydrogen-rich 
synthesis gas for combustion in the gas turbine. The CO2 is 
released from the solvent in a regeneration process that typically 
reduces pressure and/or increases temperature.
    Chemical plants currently employ such a process commercially using 
methyl diethanolamine (MDEA) as a chemical solvent or the Selexol and 
Rectisol processes, which rely on physical solvents. Physical solvents 
are generally preferred when extremely high (>99.8%) sulfur species 
removal is required. Although the required scale-up for IGCC power 
plant applications is less than that needed for scale-up of post-
combustion CO2 capture processes for PC plants, considerable 
engineering challenges remain and work on optimal integration with IGCC 
cycle processes has just begun.
    The impact of current pre-combustion CO2 removal 
processes on IGCC plant thermal efficiency and capital cost is 
significant. In particular, the water-gas shift reaction reduces the 
heating value of synthesis gas fed to the gas turbine. Because the 
gasifier outlet ratios of CO to methane to H2 are different 
for each gasifier technology, the relative impact of the water-gas 
shift reactor process also varies. In general, however, it can be on 
the order of a 10% fuel energy reduction. Heat regeneration of solvents 
further reduces the steam available for power generation. Other 
solvents, which are depressurized to release captured CO2, 
must be re-pressurized for reuse. Cooling water consumption is 
increased for solvents needing cooling after regeneration and for pre-
cooling and interstage cooling during compression of separated 
CO2 to a supercritical state for transportation and storage. 
Heat integration with other IGCC cycle processes to minimize these 
energy impacts is complex and is currently the subject of considerable 
RD&D by EPRI and others.
    Membrane CO2 Separation.--Technology for separating 
CO2 from shifted synthesis gas (or flue gas from PC plants) 
offers the promise of lower auxiliary power consumption but is 
currently only at the laboratory stage of development. Several 
organizations are pursuing different approaches to membrane-based 
applications. In general, however, CO2 recovery on the low-
pressure side of a selective membrane can take place at a higher 
pressure than is now possible with solvent processes, reducing the 
subsequent power demand for compressing CO2 to a 
supercritical state. Membrane-based processes can also eliminate steam 
and power consumption for regenerating and pumping solvent, 
respectively, but they require power to create the pressure difference 
between the source gas and CO2-rich sides. If membrane 
technology can be developed at scale to meet performance goals, it 
could enable up to a 50% reduction in capital cost and auxiliary power 
requirements relative to current CO2 capture and compression 
technology.
       post-combustion co2 capture (pc and cfb plants)
    The post-combustion CO2 capture processes envisioned for 
power plant boilers draw upon commercial experience with amine solvent 
separation at much smaller scale in the food and beverage and chemical 
industries and upon three applications of CO2 capture from a 
slipstream of exhaust gas from circulating fluidized-bed (CFB) units.
    These processes contact flue gas with an amine solvent in an 
absorber column (much like a wet SO2 scrubber) where the 
CO2 chemically reacts with the solvent. The CO2-
rich liquid mixture then passes to a stripper column where it is heated 
to change the chemical equilibrium point, releasing the CO2. 
The ``regenerated'' solvent is then recirculated back to the absorber 
column, while the released CO2 may be further processed 
before compression to a supercritical state for efficient 
transportation to a storage location.
    After drying, the CO2 released from the regenerator is 
relatively pure. However, success CO2 removal requires very 
low levels of SO2 and NO2 entering the 
CO2 absorber, as these species also react with the solvent. 
Thus, high-efficiency SO2 and NOX control systems 
are essential to minimizing solvent consumption costs for post-
combustion CO2 capture. Extensive RD&D is in progress to 
improve the solvent and system designs for power boiler applications 
and to develop better solvents with greater absorption capacity, less 
energy demand for regeneration, and greater ability to accommodate flue 
gas contaminants.
    At present, monoethanolamine (MEA) is the ``default'' solvent for 
post-combustion CO2 capture studies and small-scale field 
applications. Processes based on improved amines, such as Fluor's 
Econamine FG Plus and Mitsubishi Heavy Industries' KS-1, are under 
development. The potential for improving amine-based processes appears 
significant. For example, a recent study based on KS-1 suggests that 
its impact on net power output for a supercritical PC unit would be 19% 
and its impact on the levelized cost-of-electricity would be 44%, 
whereas earlier studies based on suboptimal MEA applications yielded 
output penalties approaching 30% and cost-of-electricity penalties of 
up to 65%.
    Accordingly, amine-based engineered solvents are the subject of 
numerous ongoing efforts to improve performance in power boiler post-
combustion capture applications. Along with modifications to the 
chemical properties of the sorbents, these efforts are addressing the 
physical structure of the absorber and regenerator equipment, examining 
membrane contactors and other modifications to improve gas-liquid 
contact and/or heat transfer, and optimizing thermal integration with 
steam turbine and balance-of-plant systems. Although the challenge is 
daunting, the payoff is potentially massive, as these solutions may be 
applicable not only to new plants, but to retrofits where sufficient 
plot space is available at the back end of the plant.
    Finally, as discussed earlier, deploying USC PC technology to 
increase efficiency and lower uncontrolled CO2 per MWh can 
further reduce the cost impact of post-combustion CO2 
capture.
    Chilled Ammonia Process.--Post-combustion CO2 capture 
using a chilled ammonia-based solvent offers the promise of 
dramatically reducing parasitic power losses relative to MEA. In the 
process currently under development and testing by Alstom and EPRI, 
respectively, CO2 is absorbed in a solution of ammonium 
carbonate, at low temperature and atmospheric pressure, and combines 
with the NaCO3 to form ammonium bicarbonate.
    Compared with amines, ammonium carbonate has over twice the 
CO2 absorption capacity and requires less than half the heat 
to regenerate. Further, regeneration can be performed under higher 
pressure than amines, so the released CO2 is already 
partially pressurized. Therefore, less energy is subsequently required 
for compression to a supercritical state for transportation to an 
injection location. Developers have estimated that the parasitic power 
loss from a full-scale supercritical PC plant using chilled ammonia 
CO2 capture could be as low as 10%, with an associated cost-
of-electricity penalty of just 25%. Following successful experiments at 
0.25 MWe scale, Alstom and a consortium of EPRI members are 
constructing a 1.7 MWe pilot unit to test the chilled 
ammonia process with a flue gas slipstream at We Energies' Pleasant 
Prairie Power Plant.
    Other ``multi-pollutant'' control system developers are also 
exploring ammonia-based processes for CO2 removal.
                      oxy-fuel combustion boilers
    Fuel combustion in a blend of oxygen and recycled flue gas rather 
than in air (known as oxy-fuel combustion or oxy-combustion) is gaining 
interest as a viable CO2 capture alternative for PC and CFB 
plants. The process is applicable to virtually all fossil-fueled boiler 
types and is a candidate for retrofits as well as new power plants.
    Firing coal only with high-purity oxygen would result in too high 
of a flame temperature, which would increase slagging, fouling, and 
corrosion problems, so the oxygen is diluted by mixing it with a 
slipstream of recycled flue gas. As a result, the flue gas downstream 
of the recycle slipstream take-off consists primarily of CO2 
and water vapor (although it also contains small amounts of nitrogen, 
oxygen, and criteria pollutants). After the water is condensed, the 
CO2-rich gas is compressed and purified to remove 
contaminants and prepare the CO2 for transportation and 
storage.
    Oxy-combustion boilers have been studied in laboratory-scale and 
small pilot units of up to 3 MWt. Two larger pilot units, at 
10 MWe, are now under construction by Babcock & Wilcox 
(B&W) and Vattenfall. An Australian-Japanese project team is pursuing a 
30 MWe repowering project in Australia. These larger tests 
will allow verification of mathematical models and provide engineering 
data useful for designing pre-commercial systems. The first such pre-
commercial unit could be built at SaskPower's Shand station near 
Estevan, Saskatchewan. SaskPower, B&W Canada, and Air Liquide have been 
jointly developing an oxy-combustion SCPC design, and a decision on 
whether to proceed to construction is expected by late 2007, with a 
target in-service date of 2011-12.
             co2 transport and geologic storage
    Application of CO2 capture technologies implies that 
there will be secure and economical storage or beneficial uses that can 
assure CO2 will be kept out of the atmosphere. The most 
developed approach for large-scale CO2 storage is injection 
into deep, well-sealed geological formations, including depleted or 
partially depleted oil and gas reservoirs and similar geologically 
sealed ``saline formations'' (porous rocks filled with brine that is 
impractical for desalination). Partially depleted oil reservoirs 
provide the added benefit of enhanced oil recovery (EOR). [EOR is used 
in mature fields to recover additional oil after standard extraction 
methods have been used. When CO2 is injected for EOR, it 
causes residual oil to swell and become less viscous, allowing some to 
flow to production wells, thus extending the field's productive life.] 
Although EOR can help the economics of CCS projects, EOR sites are 
ultimately too few and too geographically isolated to accommodate much 
of the CO2 from large-scale industrial CO2 
capture operations. In contrast, saline formations are available in 
many--but not all--U.S. locations.
    Natural underground CO2 reservoirs in Colorado, Utah, 
and other western states testify to the effectiveness of long-term 
geologic CO2 storage. CO2 is also found in 
natural gas reservoirs, where it has resided for millions of years. 
Thus, evidence suggests that depleted or near-depleted oil and gas 
reservoirs, and similarly ``capped'' saline formations will be ideal 
for storing CO2 for millennia or longer. Geologic 
sequestration as a strategy for reducing CO2 emissions from 
the atmosphere is currently being demonstrated in several projects 
around the world. Three larger-scale projects--Statoil's Sleipner 
Saline Aquifer CO2 Storage project in the North Sea off of 
Norway; the Weyburn Project in Saskatchewan, Canada; and the In Salah 
Project in Algeria--together sequester about 3-4 million metric tons of 
CO2 per year, which collectively approaches the output of 
just one typical 500 MW coal-fired power plant. With 17 collective 
operating years of experience, these projects have thus far 
demonstrated that CO2 storage in deep geologic formations 
can be carried out safely and reliably. Statoil estimates that 
Norwegian greenhouse gas emissions would have risen incrementally by 3% 
if the CO2 from the Sleipner project had been vented rather 
than sequestered.\2\
---------------------------------------------------------------------------
    \2\ http://www.co2captureandstorage.info/
project_specific.php?project_id=26
---------------------------------------------------------------------------
    Table 2 lists a selection of current and planned CO2 
storage projects as of early 2007, including those involving EOR.

                                       Table 2--Select Existing and Planned CO2 Storage Projects as of Early 2007
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                  Anticipated amount injected by:
                           PROJECT                             CO2 SOURCE      COUNTRY         START     -----------------------------------------------
                                                                                                               2006            2010            2015
--------------------------------------------------------------------------------------------------------------------------------------------------------
Sleipner                                                       Gas. Proc.        Norway            1996            9 MT           13 MT           18 MT
--------------------------------------------------------------------------------------------------------------------------------------------------------
Weyburn                                                                  Coal          Canada      2000            5 MT           12 MT           17 MT
--------------------------------------------------------------------------------------------------------------------------------------------------------
In Salah                                                       Gas. Proc.       Algeria            2004            2 MT            7 MT           12 MT
--------------------------------------------------------------------------------------------------------------------------------------------------------
Snohvit                                                        Gas. Proc.        Norway            2007               0            2 MT            5 MT
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gorgon                                                         Gas. Proc.     Australia            2010               0               0           12 MT
--------------------------------------------------------------------------------------------------------------------------------------------------------
DF-1 Miller                                                           Gas          U.K.            2009               0            1 MT            8 MT
--------------------------------------------------------------------------------------------------------------------------------------------------------
DF-2 Carson                                                          Pet Coke      U.S.            2011               0               0           16 MT
--------------------------------------------------------------------------------------------------------------------------------------------------------
Draugen                                                               Gas        Norway            2012               0               0            7 MT
--------------------------------------------------------------------------------------------------------------------------------------------------------
FutureGen                                                                Coal      U.S.            2012               0               0            2 MT
--------------------------------------------------------------------------------------------------------------------------------------------------------
Monash                                                                   Coal Australia              NA               0               0              NA
--------------------------------------------------------------------------------------------------------------------------------------------------------
SaskPower                                                                Coal          Canada        NA               0               0              NA
--------------------------------------------------------------------------------------------------------------------------------------------------------
Ketzin/CO2 STORE                                                       NA       Germany            2007               0           50 KT           50 KT
--------------------------------------------------------------------------------------------------------------------------------------------------------
Otway                                                             Natural     Australia            2007               0          100 KT          100 KT
--------------------------------------------------------------------------------------------------------------------------------------------------------
TOTALS                                                                                                            16 MT           35 MT           99 MT
--------------------------------------------------------------------------------------------------------------------------------------------------------
Source: Sally M. Benson, ``Can CO2 Capture and Storage in Deep Geological Formations Make Coal-Fired Electricity Generation Climate Friendly?''
  Presentation at Emerging Energy Technologies Summit, UC Santa Barbara, California, February 9, 2007. [Note: Statoil has subsequently suspended plans
  for the Draugen project and announced a study of CO2 capture at a gas-fired power plant at Tjeldbergodden. BP and Rio Tinto have announced the coal-
  based ``DF-3'' project in Australia.]

    Enhanced Oil Recovery.--Experience relevant to CCS comes from the 
oil industry, where CO2 injection technology and modeling of 
its subsurface behavior have a proven track record. EOR has been 
conducted successfully for 35 years in the Permian Basin fields of west 
Texas and Oklahoma. Regulatory oversight and community acceptance of 
injection operations for EOR seem well established.
    Although the purpose of EOR is not to sequester CO2 per 
se, the practice can be adapted to include CO2 storage 
opportunities. This approach is being demonstrated in the Weyburn-
Midale CO2 monitoring projects in Saskatchewan, Canada. The 
Weyburn project uses captured and dried CO2 from the Dakota 
Gasification Company's Great Plains synfuels plant near Beulah, North 
Dakota. The CO2 is transported via a 200 mile pipeline 
constructed of standard carbon steel. Over the life of the project, the 
net CO2 storage is estimated at 20 million metric tons, 
while an additional 130 million barrels of oil will be produced.
    The economic value of EOR with CCS represents an excellent 
opportunity for initial geologic sequestration projects like Weyburn. 
In addition, ``next generation'' CO2-EOR processes could 
boost U.S. technically recoverable oil resources by 160 billion 
barrels.\3\
---------------------------------------------------------------------------
    \3\ http://www.adv-res.com/pdf/Game_Changer_Document.pdf
---------------------------------------------------------------------------
                        ccs in the united states
    A DOE-sponsored R&D program, the ``Regional Carbon Sequestration 
Partnerships,'' is engaged in mapping U.S. geologic formations suitable 
for CO2 storage. Evaluations by these Regional Partnerships 
and others suggest that enough geologic storage capacity exists in the 
United States to hold several centuries' production of CO2 
from coal-based power plants and other large point sources.
    The Regional Partnerships are also conducting pilot-scale 
CO2 injection validation tests across the country in 
differing geologic formations, including saline formations, deep 
unmineable coal seams, and older oil and gas reservoirs. Figure 11* 
illustrates some of these options. These tests, as well as most 
commercial applications for long-term storage, will use CO2 
compressed for volumetric efficiency to a liquid-like ``supercritical'' 
state; thus, virtually all CO2 storage will take place in 
formations at least a half-mile deep, where the risk of leakage to 
shallower groundwater aquifers or to the surface is less likely to 
occur.
    After successful completion of pilot-scale CO2 storage 
validation tests, the Partnerships will undertake large-volume storage 
tests, injecting quantities of 1 million metric tons of CO2 
or more over a several year period, along with post-injection 
monitoring to track the absorption of the CO2 in the target 
formation(s) and to check for potential leakage.
    The EPRI-CURC Roadmap identifies the need for several large-scale 
integrated demonstrations of CO2 capture and storage. This 
assessment was echoed by MIT in its recent Future of Coal report, which 
calls for three to five U.S. demonstrations of about 1 million metric 
tons of CO2 per year and about 10 worldwide.\4\ These 
demonstrations could be the critical path item in commercialization of 
CCS technology. In addition, EPRI has identified 10 key topics where 
further technical and/or policy development is needed before CCS can 
become fully commercial:
---------------------------------------------------------------------------
    \4\ http://web.mit.edu/coal/The_Future_of_Coal.pdf

   Caprock integrity
   Injectivity and storage capacity
   CO2 trapping mechanisms
   CO2 leakage and permanence
   CO2 and mineral interactions
   Reliable, low-cost monitoring systems
   Quick response and mitigation and remediation procedures
   Protection of potable water
   Mineral rights
   Long-term liability

    Figure 12* summarizes the relationship between EPRI's recommended 
large-scale integrated CO2 capture and storage 
demonstrations and the Regional Partnerships' ``Phase III'' large-
volume CO2 storage tests.
                     co2 transportation
    Mapping of the distribution of potentially suitable CO2 
storage formations across the country, as part of the research by the 
Regional Partnerships, shows that some areas have ample storage 
capacity while others appear to have little or none. Thus, implementing 
CO2 capture at some power plants may require pipeline 
transportation for several hundred miles to suitable injection 
locations, possibly in other states. Although this adds cost, it does 
not represent a technical hurdle because long-distance, interstate 
CO2 pipelines have been used commercially in oilfield EOR 
applications. Nonetheless, EPRI expects that early commercial CCS 
projects will take place at coal-based power plants near sequestration 
sites or an existing CO2 pipeline. As the number of projects 
increases, regional CO2 pipeline networks connecting 
multiple industrial sources and storage sites will be needed.
         policy-related long-term co2 storage issues
    Beyond developing the technological aspects of CCS, public policy 
need to address issues such as CO2 storage site permitting, 
long-term monitoring requirements, and liability. CCS represents an 
emerging industry, and the jurisdiction for regulating it has yet to be 
determined.
    Currently, efforts are under way in some states to establish 
regulatory frameworks for long-term geologic CO2 storage. 
Additionally, stakeholder organizations such as the Interstate Oil and 
Gas Compact Commission (IOGCC) are developing their own suggested 
regulatory recommendations for states drafting legislation and 
regulatory procedures for CO2 injection and storage 
operations.\5\ Other stakeholders, such as environmental groups, are 
also offering policy recommendations. EPRI expects this field to become 
very active soon.
---------------------------------------------------------------------------
    \5\ http://www.iogcc.state.ok.us/PDFS/
CarbonCaptureandStorageReportandSummary.pdf
---------------------------------------------------------------------------
    Because some promising sequestration formations underlie multiple 
states, a state-by-state approach may not be adequate. At the federal 
level, the U.S. EPA published a first-of-its-kind guidance (UICPG # 83) 
on March 1, 2007, for permitting underground injection of 
CO2.\6\ This guidance offers flexibility for pilot projects 
evaluating the practice of CCS, while leaving unresolved the 
requirements that could apply to future large-scale CCS projects.
---------------------------------------------------------------------------
    \6\ http://www.epa/gov/safewater/uic/pdfs/
guide_uic_carbonsequestration_final-03-07.pdf
---------------------------------------------------------------------------
           long-term co2 storage liability issues
    Long-term liability of storage sites will need to be assigned 
before CCS can become fully commercial. Because CCS activities will be 
undertaken to serve the public good, as determined by government 
policy, and will be implemented in response to anticipated or actual 
government-imposed limits on CO2 emissions, a number of 
policy analysts have suggested that the entities performing these 
activities should be granted a large measure of long-term risk 
reduction.
         rd&d investment for advanced coal and ccs technologies
    Developing the suite of technologies needed to achieve competitive 
advanced coal and CCS technologies will require a sustained major 
investment in RD&D. As shown in Table 3, EPRI has estimated that an 
expenditure of approximately $8 billion will be required in the 10-year 
period from 2008-17. The MIT Future of Coal report estimates the 
funding need at up to $800-850 million per year, which approaches the 
EPRI value. Further, EPRI expects expected that an RD&D investment of 
roughly $17 billion will be required over the next 25 years.
    Investment in earlier years may be weighted toward IGCC, as this 
technology is less developed and will require more RD&D investment to 
reach the desired level of commercial viability. As interim progress 
and future needs cannot be adequately forecast at this time, the years 
after 2023 do not distinguish between IGCC and PC.

                              Table 3--RD&D Funding Needs for Advanced Coal Power Generation Technologies with  CO2 Capture
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                         2008-12          2013-17          2018-22          2023-27          2028-32
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Estimated RD&D Funding Needs                                         $830M/yr         $800M/yr         $800M/yr         $620M/yr         $400M/yr
(Public + Private Sectors)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Advanced Combustion, CO2 Capture                                                25%              25%              40%
                                                                                                                                   80%              80%
-----------------------------------------------------------------------------------------------------------------------
Integrated Gasification Combined Cycle (IGCC), CO2 Capture                      50%              50%              40%
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 Storage                                                                     25%              25%              20%              20%              20%
--------------------------------------------------------------------------------------------------------------------------------------------------------

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

    The Chairman. Well, thank you all very much for your 
testimony. I think it's very useful.
    Let me just start and do 5 minutes of questions and we'll 
give everyone a chance to ask some questions here and see if we 
want to do a second round after that.
    Let me ask you, Mr. Hollinden, first. I know one of your 
recommendations here relates to ultra- supercritical pulverized 
coal and how, I think you say, we should pursue a large-scale 
demonstration project to spur development of ultra-
supercritical pulverized coal technology.
    We had a hearing with the folks from MIT, John Doitch and 
Ernie Menise, I believe testified. I got the impression from 
that hearing that they thought that ultra- supercritical 
technology had been demonstrated in various parts of the world, 
that they're using it in Germany today, they're using it in 
Japan, they're using it in various places. We have not used it 
for a variety of reasons, but why do we need to reinvent the 
wheel? Why can't we take the technology that has been 
demonstrated elsewhere in the world and put it into application 
here? Or am I confused about whether it's been demonstrated?
    Mr. Hollinden. Well, there's a lot of forms of 
supercritical. There's supercritical, ultra-supercritical, and 
advanced ultra-supercritical. We're talking about advanced 
ultra-supercritical here, so there may just be a difference in 
the terminology that we're using here.
    For instance, a conventional plant would operate at 35 
percent, maybe, efficiency. A supercritical plant might operate 
at 39, an ultra-supercritical at 42 to 44 and the advanced 
ultra-supercritical at 48. We're looking at the advanced ultra-
supercritical. I think that the MIT people were talking about 
the ultra-supercritical plants.
    The Chairman. So you're saying that what you're talking 
about seeing demonstrated at commercial scale has not been 
demonstrated at the commercial scale as yet.
    Mr. Hollinden. That's correct.
    The Chairman. Anywhere in the world?
    Mr. Hollinden. That's correct.
    The Chairman. Am I right, though, that even for the ultra-
supercritical that gets you to 42 percent, we have not 
implemented or used that technology to the extent it's been 
used elsewhere in the world?
    Mr. Hollinden. Yes, sir. That's correct.
    The Chairman. Why is that? Why are we so behind some of 
these other industrial countries in doing that?
    Mr. Hollinden. You know, as representative of the National 
Coal Council, you know, our study here was related to 
CO2 control. So, I feel like that, you know, I could 
answer that as, from my, according to me----
    The Chairman. Yes, go right ahead.
    Mr. Hollinden [continuing]. Not, for the Council--
    The Chairman. Don't, just give us your own perspective on 
it.
    Mr. Hollinden. You know, I came out of the coal industry, I 
mean, I worked for Tennessee Valley Authority for a number of 
years, I've been involved in coal. In the early days, these 
technologies were not very reliable. So, you know, in the 
United States we put plants on, coal was cheap and we wanted 
the plants to run. So we put on technologies that ran very 
effectively, very reliably without much interest, I shouldn't 
say interest, but much need for efficiency because coal was so 
cheap. So, it didn't make a whole lot of difference.
    The Chairman. So efficiency was much less of a priority 
than reliability?
    Mr. Hollinden. Absolutely, absolutely.
    The Chairman. So, we didn't really put much pressure on, or 
much priority on getting the most efficient possible plant?
    Mr. Hollinden. That is the way it is today, too.
    The Chairman. Right. OK.
    Mr. Phillips, let me ask you--you made reference to the 
dispatch order and the fact that even if we were to build some 
of these highly efficient plants, the reductions in emissions 
would not be that great because they would be very far down in 
the dispatch order. I thought that's what I heard you say.
    Mr. Phillips. That's right, yes.
    No--one of the reasons why those costs increased so much is 
that, for instance, in a pulverized coal plant you're going to 
be using almost 30 percent of the plant's output to compress 
the CO2 and put it in the pipeline. So therefore, 
the overall, the effective efficiency of the plant goes down 
dramatically and because of that the operating costs of the 
plant for a given amount of megawatts is higher.
    So, just to get the lowest cost electricity, the way it's 
run now, you know, the cheapest plant goes on first, the second 
cheapest second, and so forth. So these plants would be further 
down the dispatch order, unless there's some kind of an 
incentive for them to capture that CO2 and put it in 
the ground. So, that's what I was talking about. We're probably 
looking at something on the order of $20 a ton or so.
    The Chairman. The dispatch order is currently and 
historically determined on the basis on what gets you the 
cheapest power?
    Mr. Phillips. That's correct. Particularly in our 
deregulated States where there's a, you know, competitive 
generation. It's simply a matter of who bids the lowest. They 
get picked first.
    The Chairman. What if there were a change in policy that 
got us to a point where we had a dispatch order that was 
dictated by how you get the fewest emissions?
    Mr. Phillips. Well, that would certainly change things.
    The Chairman. Would that significantly incentivize 
development of these technologies in a way that they are not 
currently incentivized, or use of these technologies, I guess?
    Mr. Phillips. Right. I haven't really looked into the 
details. I'm more of a technologist than a policy person, so I 
can't say specifically, but obviously right now, the way the 
situation is, there's not an incentive and so any type of 
mechanism that did make an incentive would obviously be a help.
    The Chairman. All right. I've used my time.
    Senator Domenici, go right ahead.
    All right. Senator Craig, you, would you? I've got a list 
here.
    Senator Craig. I was going to say, I was not here first, 
Mr. Chairman.
    The Chairman. OK.
    I guess Senator Barrasso was next. Excuse me, I got out of 
order here. Go ahead.

         STATEMENT OF HON. JOHN BARRASSO, U.S. SENATOR 
                          FROM WYOMING

    Senator Barrasso. Thank you very much, Mr. Chairman.
    As you know, Wyoming produces more coal than any other 
State, almost 500 million tons of coal, and people in Wyoming 
are familiar with the unit trains, the 100 cars carrying coal 
out of the State. As they talked, for every four cars, three 
are carrying coal, and one is carrying water, because that's 
how it is until it gets to be used.
    People, as consumers, want affordable energy, and we've 
become more dependent on international sources of energy, and 
the more we can do to become energy independent, I think the 
better it is for our Nation, and clearly, the better it is for 
my State.
    The technology needs to be there, for efficiency, so that 
we can generate more electricity from the same amount of coal, 
but the people of Wyoming would agree that we're at a unique 
position now. I've been in the legislature in Wyoming, 
legislators have been to the mines, have seen the technology, 
we have an entire Wyoming infrastructure authority, looking at 
some of the things that are important to us, as a State, 
because we think we can be very helpful in making the Nation 
energy independent.
    In a program called Leadership Wyoming, for 7 years in a 
row, people travel around the State, bipartisan, looking at 
what we can do, and we look at coal technology, coal-to-gas, 
coal-to-liquids--ways to convert coal into electricity and then 
build the transmission line to move the energy in a more 
efficient way.
    When I look at this--and you say you want to try to find 
the right incentives for the carbon dioxide, one of the 
thoughts is, carbon dioxide can be used for enhanced oil 
recovery from oil wells, and you know, if you could get the 
technology so that, in a place where you have oil wells, like 
Wyoming, and you have coal, like Wyoming, and the carbon 
dioxide can be used from one to the other, than the carbon 
dioxide can be pumped into the wells to enhance, and gain more 
energy.
    I guess the first question would be--wouldn't Wyoming be 
the best place in the world to do all of these things? Even 
though you're all from the East Coast?
    The additional question is, how do we get this done? I 
mean, you're looking for incentives, but we need to get this 
technology advanced, throwing a lot of money at it in 1 year 
isn't going to solve it in a year. There's a Wall Street 
Journal article yesterday, Australia Pushes Clean Coal, there, 
you know, coal reserves in Australia and in the United States, 
in China--is America going to have to lead the world in coming 
up with the technology, and then sharing it internationally 
with some of these others? What's the best way to get that 
done?
    Mr. Bauer. I appreciate your insights, Senator. The 
question--obviously EOR is probably one of the early places 
that we can use CO2. In fact, one of the issues and 
challenges of EOR, is where do you get the CO2, so 
most of the EOR, to date, in the country has been using 
naturally occurring CO2, and most of it has been in 
the Permian basin.
    Anthropogenic CO2 is about three to four times 
as expensive, and that puts a chill on the economics around 
EOR. So, having an abundant supply of CO2 that was 
at cost, substantially more competitive than it presently is 
from man-made, would be very helpful.
    So, that leads to your question about capturing 
CO2, and using it effectively. I think the simple 
answer to that is yes, but right now, the policy and dynamics 
around capture that don't really foster that effort, it's 
purely a marketplace decision, and as you're probably aware, 
the gasification facility in North Dakota sends EOR up to the 
Weyburn Facility in Canada, to do EOR. That CO2 
pipeline was invested in by DOE, the Federal Government, to 
evaluate how does that work? It's been very, very, profitable 
for the company, and I think the information we've gathered 
about large-scale injection of CO2 has been very 
helpful.
    I don't know if that helps you with your answer, but I 
think that capture technology that will get the economics down 
to capturing and separating CO2 is an essential 
part, just as Jeff was talking about, as far as just dealing 
with electricity costs.
    Senator Barrasso. It just seems, Mr. Chairman, that so much 
has to do with BTUs, and how to capture the energy, and how to 
do it in a clean, efficient way, and I think that we can really 
go a long way, when you just look at the amount of coal 
resources that are available in this Nation. I mean, there is 
this source of energy, and the more that we can do, and the 
more that we can encourage, you know, as a Government, to put 
clean coal, and all those technologies, coal liquification into 
gas, into liquids, the better it's going to be for our Nation, 
and our own energy independence.
    Thank you, Mr. Chairman.
    The Chairman. Thank you very much.
    Senator Salazar.

          STATEMENT OF HON. KEN SALAZAR, U.S. SENATOR 
                         FROM COLORADO

    Senator Salazar. Thank you. Thank you very much, Chairman 
Bingaman, and Senator Domenici for holding this hearing. I 
remember our committee hearings on the Energy Policy Act of 
2007, whatever the name is, that we just passed. The dialog 
that we had in this committee with Senator Thomas, Senator 
Barrasso, and Senator Tester who, and others who were very 
interested in the coal issue, and how we can deal with the most 
abundant resource that we have here in America today, and try 
to use it as one of those items on the menu that gets us to 
address the very critical energy issues that our country faces.
    Today, as I understand, we're looking at--based on the 
latest oil prices, $72 per barrel, and I think we're going to 
continue to see a robust agenda on the part of the United 
States Congress, to try to figure out ways of moving forward 
toward energy independence. I've always said those drivers are 
not only National security and economic, but they also now have 
to do with our environmental security here as a country, and 
that seems to be the challenge with respect to how we move 
forward with coal resources.
    So, my question to you has to do with respect to how we 
might be able to reconcile the use of coal with the challenge 
that we face, regarding global warming, and how, specifically 
we might be able to use coal-powered energy for hybrid plug-in 
vehicles. I think two-thirds of our oil today is currently used 
for transportation. Plug-in hybrids, I think, have a tremendous 
opportunity in terms of dealing with the transportation issue, 
and it also seems to me to provide a great opportunity for our 
coal resources and our coal industry to be able to produce 
electricity and to sequester the carbon from those plants.
    So, I'd just like, starting with you, Carl, going through 
and commenting how the hybrid plug-in technology is also 
related to what we do with coal development and carbon 
sequestration.
    Mr. Bauer. I think it's an astute observation, Senator, we 
did a study at NETL just recently in looking at the 
alternatives to liquid transportation fuels, and plug-in 
hybrids was one of the areas that we thought was a way to 
reduce the dependency on the imports, or the demand on fuel 
liquids.
    So, obviously that increases the demand for electricity, 
and 50 percent of electricity comes from coal. I would suggest 
that the large base load plants--nuclear and coal--as well as 
renewable portfolios, would have an opportunity to contribute 
more to transportation fuel offset.
    So, back to your question--how does coal deal with that? Or 
even natural gas combined cycles, when you have a 
CO2 issue? Again, we go back to having good, solid 
technology for capture at a lower economic cost, and the 
ability and the regulatory framework for decisions to be made 
in the marketplace to take that CO2 captured and put 
it someplace for storage, long-term, or we're looking at trying 
to find ways to use CO2 as a product, not just as a 
waste problem.
    So, for example, we're stimulating algae growth to see what 
we can do to get more efficiency out of the carbon by creating 
biodiesel from the algae. That adds to the offset of the 
carbon, and provides electricity for plug-ins, and you have two 
ways of addressing liquid fuels that way.
    Senator Salazar. Mr. Hollinden.
    Mr. Hollinden. The National Coal Council did not look at 
hybrid coal technologies, so I would be speaking for myself, as 
opposed to the Council. If that's OK?
    Senator Salazar. Go ahead, give me a quick remark and then 
we'll go with someone else.
    Mr. Hollinden. I think one of the overriding issue that I 
have with all of these technologies, is a continued negative 
press we get with ``dirty coal.'' You know, and it doesn't help 
our communities, when they hear this, that coal continues to be 
dirty. Every time we pick up a paper, we hear of ``dirty coal'' 
and ``clean gas.''
    In fact, when these clean coal technologies, advanced coal 
combustion technologies, gasification technologies are 
implemented in 15, 10 or 15 years with CO2 control, 
they're going to be cleaner than gas. It's never put in the 
paper like that.
    Senator Salazar. Well, let me----
    Mr. Hollinden. I think our folks need to understand, our 
people need to understand----
    Senator Salazar. [continuing]. Let me just say this, Jerry, 
from my point of view, we have struggled in this committee, 
many of us come from coal-rich States, and I do, and I support 
the coal industry in my State. How we reconcile the development 
and use of our coal with the environmental realities of the 
consequence of coal, is something that we all struggle with.
    It seems to me that so long as transportation consumes two-
thirds of our energy, it's going to continue to be a National 
security driver that all of us are going to agree, we need to 
do something with. So, I would encourage you and the National 
Coal Council and others to look at how we use coal in 
connection with our transportation needs, and specifically 
looking at plug-in hybrids.
    Jeff, can you just make a quick comment on it?
    Mr. Phillips. Yes, EPRI has been looking at plug-in hybrids 
for quite awhile, and in fact, we just issued a joint report 
with NRDC on the impact of plug-in hybrids on overall emissions 
in the United States economy, and it shows that indeed, this is 
a favorable pathway.
    I mean, when you think about it, as costly as it may be to 
put CO2 capture on the back end of a coal plant, it 
would be even more costly to put it on the back end of an 
automobile.
    If you look at a future electric power sector that is 
decarbonized with solar/wind, solar and coal plants with carbon 
capture, we basically will have a carbon-free fuel that you 
could, then, to run your automobiles.
    Senator Salazar. OK. Thank you.
    Mr. Phillips. I think it's a very wise policy to pursue.
    Senator Salazar. My time is up. Thank you.
    [The prepared statement of Senator Salazar follows:]

     Prepared Statement of Hon. Senator Ken Salazar, U.S. Senator 
                             From Colorado
    I want to thank Chairman Bingaman and Ranking Member Domenici for 
holding today's hearing on clean coal technologies, and efforts to 
capture and store carbon dioxide. I am proud of our achievements on 
clean coal technologies in the Energy Policy Act of 2005 and on carbon 
sequestration in the Energy Savings Act of 2007. There is more work to 
do, however, particularly given the very real near-term as well as 
longer-term opportunities for carbon capture and storage and the 
commercial deployment of advanced coal utilization technologies. So I 
appreciate the efforts of Chairman Bingaman, Ranking Member Domenici, 
and the committee staff putting this hearing together.
    My home state of Colorado is endowed with many natural resources, 
including vast coal resources. In Colorado, 71% of the electricity we 
produce is generated with coal. Colorado consumed 18.9 million tons of 
coal in 2004, generating 37.5 million megawatts of electricity. Most of 
this coal comes from Colorado, but some of it is from Wyoming.
    Coal is our most abundant domestic energy source. It provides more 
than 50% of our nation's electricity needs, and America has enough coal 
to last more than 200 years. Unfortunately, CO2 pollution 
from coal combustion is a main cause of global warming, which threatens 
my state's water resources, our economy, and our quality of life.
    Fortunately, there seems to be more than one way to reconcile coal 
use with protecting our climate, through new low-carbon technologies 
such as Integrated Gasification Combined Cycle (IGCC), Oxycoal and 
ultra-supercritical combustion technologies. In addition, advancements 
in capturing carbon and safely sequestering it underground will allow 
our country to use coal, and at the same time reduce CO2 
emissions. I am proud of the work this Committee did in the Energy 
Savings Act of 2007 to promote research, development and deployment of 
carbon capture and sequestration technologies, and to do an assessment 
of our nation's carbon storage capacity. What we learn from the 
national assessment may be valuable in determining optimal locations to 
place coal gasification and other new power plants to put them near 
areas where the CO2 emissions can be safely sequestered.
    Advances in technology indicate that a coal plant using combined 
cycle technology, carbon capture and storage, and biomass as part of 
the fuel source can result in far lower greenhouse gas emissions. It is 
my understanding that even some coal-to-liquid processes can use up to 
30% biomass in the feedstock, which reduces the CO2 
emissions from the process. The use of a renewable fuel like biomass in 
these plants presents a great opportunity to allow for an expanded use 
of coal without adding to global warming.
    I also believe plug-in hybrid electric vehicles present an 
important opportunity to utilize coal--to make electricity--as a source 
of transportation fuel, and thus to displace large quantities of 
petroleum-based transportation fuels. Because two-thirds of our 
transportation fuels are derived form petroleum products, plug-in 
hybrid electric vehicles powered by electricity generated from 
renewable sources and from advanced coal power plants with carbon 
capture and storage will enable us to achieve greater energy security, 
economic security and environmental security in this country.
    Thank you Chairman Bingaman and Ranking Member Domenici for holding 
today's hearing so that we can learn more about how our country's 
greatest fossil fuel resource can be used to power our homes and 
businesses as well as to fuel our automobiles.

    The Chairman. Senator Domenici. Senator Craig. Either one, 
whoever wants to go.

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

    Senator Domenici. All right, thank you. Thank you very 
much, Mr. Chairman.
    Let me say that it's very, very important that a hearing 
like this one occur. We must go before our Congress, and before 
the people of this country the facts about coal, and coal in 
our future.
    Incidentally, if you wonder what deep thoughts I was 
exchanging views with the man on my left and the man on my 
right, in case you wonder, the three of you, I was telling him, 
each of them, that you are dressing much better these days.
    [Laughter.]
    Senator Domenici. Mr. Salazar, I was talking about the coal 
industry being dressed up in pretty good attire these days, 
there must be that there's something good on the horizon. In 
any event, I'm with you.
    I wanted to ask some questions, panel one. Carl--the 
Department of Energy's goal is, ``To develop by 2012, fossil 
fuel systems with 90 percent CO2 recapture, 99 
percent storage, at less than a 10 percent increase in the cost 
of energy.'' I've noticed that the National Coal Council makes 
a clear recommendation in their report to the Secretary that 
technologies should not be abandoned today, just because they 
can not immediately meet high capture expectations, early in 
their development cycle.
    Can you explain this concept in greater detail? It is an 
important one--to what extent do the existing clean coal 
programs at the Department account for it?
    Mr. Bauer. Thank you, Senator. Yes, I will attempt to 
clarify that.
    I believe what the National Coal Council is recommending, 
and what the Department of Energy and National Energy and 
Technology do in the implementation of fossil program, it's 
R&D, so it wouldn't be R&D if we knew the answer, we'd just go 
and do it.
    As we go through R&D, we do systems analysis of the 
research, as well as the application, to see that if the 
technology would, in fact, work, would it be economically 
viable, so that someone would buy it and put it to work? 
Because they have to go back into the dispatch rate base.
    However, having said that, it depends on what stage of 
development the technology is in. Early in the technology, an 
analysis that suggests it doesn't work, may suggest why--from 
the economic standpoint--it wouldn't be acceptable, and that 
could then be resolved with further technical efforts. So, 
instead of abandoning that approach, it's wise to recognize the 
issue, and see how that issue can be further dealt with, 
technologically, so that technology does come forward.
    It's also important for us to have multiple paths forward, 
because as they go down the line, go to the races, not all of 
them are going to make it to the other end, but the more 
opportunities we have to get to the other end within the budget 
allowance, it makes good decisions to get there. It also, 
chronologically speaking, gets us to technological solutions, 
sooner, and I hope that helps, Senator.
    Senator Domenici. You got it.
    In terms of our ability to retrofit the existing coal fleet 
for CO2 capture and storage, we must account, not 
only for predictable increases in electricity demand, but also 
the inevitable losses in the output of existing plants that 
seek to incorporate and capture technologies.
    What implications do you believe this trend will have for 
the pace at which carbon dioxide capture, and existing plants, 
can be achieved? Even once those technologies have reached 
commercial availability? Carl, you want to do it?
    Mr. Bauer. OK, I'll take that on.
    I think that, again, as Jeff alluded in his testimony--if 
we were just to, for example, to quickly provide an insight to 
this. If we were to take today, and then Congress put into law, 
and regulations were in effect, they would say that we have to 
capture half of the CO2 from the existing fleet.
    Right now, our calculations suggest, on existing 
technology, that would be about a 15 percent reduction in 
delivery of electricity, 15 percent reduction in the efficiency 
at the end point of delivery.
    That translates to the need, if you want to deliver the 
same amount of electricity that we presently have--when you 
think about with the plug-ins, you need more--that would mean 
we need 42 gigawatts of additional power capacity to offset the 
loss of power required to deal with the CO2 capture 
and sequestration challenge of taking 50 percent of the 
CO2 from the existing fleet, and putting it into 
sequestration.
    That's a huge--42 gigawatts, coupled with all the other 
growth that we need--is a huge amount of power to generate, or 
to replace, figuring a plant takes 6 to 8 years to get through 
permitting and construction, whether it's nuclear or coal, 
those are pretty ideal times. It's probably more like 8 to 10 
years, natural gas combined cycle, if we're lucky, 3 to 4 
years, but then for every 25 gigawatts of gas, you need another 
1 trillion cubic feet of natural gas supply.
    So, the challenge is very surmountable, and the economic 
impacts. By the way, if we did that, our numbers predict about 
an increase to about $85 a megawatt, compared to existing 
fleet, presently $25 megawatt as of older plants. So, it's a 
substantial economic, not just technological challenge.
    Senator Domenici. Thank you very much.
    Mr. Phillips. Can I also respond to that, Senator?
    Senator Domenici. Jeffrey, it's your question, your answer, 
too.
    Mr. Phillips. Yes, well, EPRI recently put out what we call 
our Prism Analysis, or some people call it our wedge chart, 
which shows how we could remove CO2 from the 
emissions of the electric power sector using various projects, 
and in that analysis we show that you could drop down to 1990 
CO2 emission levels by 2030, and in that analysis, 
we did not assume any retrofitting of CO2 capture. 
Only CO2 capture on new coal plants.
    Now, we're also doing very aggressive things on the energy 
use side--better efficiencies in the homes, increases in solar 
and wind usage, increases in nuclear power, and higher 
efficiency for existing plants. That was the one retrofit that 
we said was, you can go back into existing plants and improve 
their efficiency, and reduce emissions by maybe 5 percent just 
doing that.
    The problem with retrofitting is that some plants, it might 
be cost-effective, other plants, they've already had so many 
other things retrofitted to them, that you'd have to put the 
CO2 capture stuff on the other side of the highway, 
and it would get very, very costly.
    Senator Domenici. Thank you very much.
    Thank you, Mr. Chairman.
    [The prepared statement of Senator Domenici follows:]

Prepared Statement of Hon. Senator Pete V. Domenici, U.S. Senator From 
                               New Mexico
    Good morning, I want to thank the Chairman for scheduling this 
important hearing. Coal is our most affordable and abundant fossil 
fuel. We generate over half of our electricity with coal. But coal is a 
versatile feed-stock as well, and electricity is not the only product 
we can make from it. During our recent energy debate, there was a 
desire to support new alternative uses of coal. However, there was 
stiff resistance to those efforts, largely based on concerns about the 
cleanliness of coal.
    The term itself, ``clean coal'', is a moving target, however. Its 
definition, and the technology needed to meet that definition, has 
evolved over time. We have devoted significant resources over the years 
to making coal clean. We now find ourselves focused primarily on carbon 
dioxide and its impact on global climate change. In that context, we 
can, and should, continue to make coal cleaner.
    It is important to do so, given that coal accounts for nearly one 
third of our carbon dioxide emissions. This effort will be undertaken 
at a massive scale, and it will be a challenging one.
    To provide perspective, consider that the amount of coal produced 
during a typical week this month would, if shipped by rail, fill 2,100 
trains with 100 cars each and stretch across 2000 miles--that's two-
thirds the width of the entire United States. We use nearly 1.2 billion 
tons of coal per year, and that figure is expected to increase with 
time. The challenge presented by the environmental improvements we seek 
is equally significant, but I believe we are up to that challenge.
    In 1989, our country was generating 1,583 billion kilowatt hours of 
electricity from coal. By 2005 that figure had increased by 27 percent 
to 2,013 billion kilowatt hours per year.
    During those same 16 years, the emissions we have traditionally 
used to define clean coal went down significantly. Sulfur dioxide 
decreased by 48 percent per unit of power generated, and nitrous oxide 
went down 66 percent.
    We do not owe this progress to a purely regulatory approach, but to 
innovators and investors who have cooperated with the federal 
government to develop and commercialize better technologies.
    We have always sought to cushion the blow associated with 
environmental limitations through public-private partnerships, and the 
case of carbon dioxide should not be an exception. The task before us 
now is to continue--and expedite--this historical trend of 
environmental improvement.
    Today, we will hear from witnesses to clarify the appropriate 
definition of what ``clean'' coal is. We must know what technologies 
can be deployed to meet this definition and when they will be 
available. Make no mistake--this will be expensive, so we must also 
know the costs in order to minimize the financial burden passed along 
to consumers.
    This conversation must take place in the context of our nation's 
environmental, economic and energy security priorities. In all 3 of 
these categories, it is in our best interest to expand, not limit, our 
future use of clean coal.
    I thank the witnesses for appearing today and look forward to 
hearing their testimony.

    The Chairman. Thank you.
    Senator Dorgan.

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

    Senator Dorgan. Mr. Chairman, Thank you very much. It's 
interesting that we meet during a week when oil is at $78 a 
barrel, and are now talking about coal, which of course, is our 
most abundant resource. It's also interesting that all of these 
hearings have changed, because we've come to an intersection 
that's a new road for us, and a new intersection. We are not 
going to talk about coal development in the future, without 
talking about climate change and CO2 capture and 
sequestration.
    The question on that is not whether, it is how, and when? 
Because only addressing how and when, only then will we be able 
to--in my judgment--have full use of the most abundant resource 
that we have.
    I wanted to mention a couple of things. Senator Domenici 
and I chair the Appropriations Committee that funds these 
projects and accounts, and Senator Domenici has chaired that 
same Subcommittee on Appropriations, and now, is now the 
Ranking Member. For example, we have--carbon sequestration in 
2007, we had $100 million. The Administration has requested in 
their 2008 budget, $79 million. We put in $132 million. So, the 
Administration was proposing 20 percent less than we actually 
spent in 2007.
    Advanced research, about the same, almost a third less. You 
know, a range of these accounts are not being funded the way--
one would expect if this is a priority, than you boost funding 
in research, especially in these areas of carbon capture and 
sequestration. That has not been the case.
    We have, however, increased that funding in our 
subcommittee, believing it's a priority.
    I want to mention one more thing, and then I'm going to ask 
you a question. In North Dakota, most of you know we have the 
nations only coal gasification plant, we make synthetic natural 
gas from lignite coal. We also have built a pipeline to the oil 
fields in Alberta to transport CO2. We capture about 
50 percent of the CO2, we send it to Alberta, 
Canada, they invest it in their oil wells, to increase 
productivity of marginal oil wells.
    Now, I read recently that there are--and I don't know 
whether this is a good report--but I read that some suggest 
that there are over 200 billion barrels of oil that remain as 
residual oil in partially produced wells, or mature oil fields. 
By contrast, for example, the Saudis, we believe, have reserves 
of around 270 billion--that's the largest reserve in the world. 
This 200 billion would be about 10 times of what we expect our 
reserved to be.
    If that's the case, and if we can find beneficial use of 
carbon sequestration, by investing in these oil fields, and 
dramatically increasing the supply of domestic oil, we'll have 
done a lot of things that are important: unlocked our ability 
to use coal, dramatically improved our capability to increase 
oil supplies, and also protected our air shed.
    That's why this hearing is so unbelievably important. 
Because, I mean, it will determine what kind of energy future 
we have, if we get these things right. I'm not certain, by the 
way, Future Gen is the right approach, by building one huge 
plant. I think there are many ways to try to figure out, how 
you combine various technologies, and evaluate what the 
combination of various technologies mean, in terms of practical 
capability for the future? We've sort of loaded this into one 
big wagon and said, ``All right, we're going forward with this 
big wagon.'' I'm not so sure that we shouldn't have broken it 
into a number of different parts.
    Having said all that, let me ask--are the three of you 
optimistic, or pessimistic, or have mixed feelings about the 
proposition of our being able to really find the methods of 
capture and sequestration which unlocks our ability to use this 
resource? Do you feel optimistic we can do this in a reasonable 
timeframe, and do it well, Carl?
    Mr. Bauer. I'm very optimistic we can do that. I think 
we've already had, through the regional partnerships, and the 
National Laboratories and the universities that have been 
engaged heavily in this, as well as the oil and gas industry, 
which has been doing EOR for a long time, a lot of information 
that indicates carbon capture and storage, the storage part is 
very doable. We know we can do capture today, the problem with 
capture today is the economics around it, can we afford to do 
it today at the price that it would drive our electricity price 
in this country? Electricity and GDP seem to run very parallel 
to each other, as opposed to energy, which is slightly lower, 
because we are much more efficient at using our energy.
    So, I believe the answer is yes, we can do that. Having the 
regulatory framework for an industry that doesn't do that as a 
normal cause is important for them to make the business 
decisions and be able to build it into the rate base, or 
whatever approvals they have to go with the Commissioners.
    I also believe we have capture and separation technologies 
that over the next decade will substantially improve the costs, 
and get toward the DOE goals. I can go over those another time, 
but I believe so.
    Just as one sidelight to the EOR--for all of the EOR that's 
been done in this country to date, we have only produced 1 
billion barrels of oil from EOR. So, the Senator's right--there 
is a 200 billion barrels, or if you go down below 5,000 feet, 
there's probably 400 billion barrels that are possible, that 
could be recovered, however, that's technologically possible, 
not economically viable without better technology or cheaper 
CO2.
    Senator Dorgan. Are the others optimistic?
    Mr. Hollinden. Yes, I am, too. From a different 
perspective, I'm with an architect engineering company, and you 
know, over the last 30 years, every challenge that's been 
thrown at the coal and utility industry has been met, whether 
it's been SO2, whether it's been NOX, 
whether it's been particulates, now it's mercury----
    Senator Dorgan. Mercury.
    Mr. Hollinden [continuing]. Now we're looking at 
CO2, you know? I mean, we can bring the solutions, 
you know, to the table. I mean, that's what we're here for, 
and, as engineering companies, and developers, and as my 
colleague just said--it's a function of cost, and risk today of 
these technologies.
    Remember, we can develop CO2 removal, quickly, 
but that CO2 has to go somewhere. I think we've got 
to remember that we've got to do this simultaneously. We've got 
to be developing sequestration technology at the same time 
we're developing CO2 control. Because, we can be 
removing CO2, and have no place to put it. It's a 
lot different from the SO2 removal, and 
NOX in there, where you can put sulfur dioxide 
material, you know, in wall board plants on the ground. You 
remove CO2, and you haven't demonstrated a place to 
put it, you know, you have to shut that facility down.
    Senator Dorgan. Jerry, you complained about not getting 
good press for the coal industry, I'd remind you that the 
statement--bad news travels halfway around the world before 
good news gets its shoes on. It's something we understand here, 
and I understand, I understood your complaint.
    Mr. Phillips.
    Mr. Phillips. Yes, Senator, I am also optimistic, but it's 
going to take a sustained effort. I told some engineering 
students at Virginia Tech, this is your moon shot, this is your 
generation's moon shot, that's the level of effort that it will 
take to make this happen. We did put a man on the moon, and we 
did it in 10 years. We're talking about something that we need 
to do in 20 years, it can happen, and I think that EOR is going 
to be a very key bridge to making that happen.
    Because, as you point out, you can make money from that. I 
used to work in the oil business, and so I'll give you a 
general rule of thumb--take the price of oil in dollars, per 
barrel, divide that by 2, and that's the price in dollars per 
ton that the oil industry should be willing to pay for 
CO2 in enhanced oil recovery. So that's if it's $73 
today, then that's what--about $36.5 per ton.
    Now, unfortunately, those numbers right there are based on 
technology that's probably going to cost us $50 a ton. So, it 
doesn't quite cover the cost, but it sure covers a lot. If we 
could use that, his, Carl Bauer's program has done an analysis 
that shows that if we just captured CO2 from half of 
the new power plants that are built between now and 2025, use 
it for enhanced oil recovery, we could double United States 
domestic oil production.
    Senator Dorgan. That's a very important piece of 
information. I've gone over my time, but I thank the Chairman.
    Thank you very much.
    The Chairman. Thank you very much.
    Senator Craig.

        STATEMENT OF HON. LARRY E. CRAIG, U.S. SENATOR 
                           FROM IDAHO

    Senator Craig. Well, in that very exciting concept, Jeff, 
you excited me more when you talked about your desire to have 
an AMC Pacer. I, too, wanted one.
    [Laughter.]
    Mr. Phillips. I had to settle for a Gremlin.
    Senator Craig. I didn't even get that far.
    Well, we were farming and ranching in those days, and there 
was no money in cattle, so my dad and I couldn't afford even 
the Gremlin, let alone the Pacer.
    [Laughter.]
    Senator Craig. That's probably why I drive a Honda Element 
today. Something in my mental background that would suggest I 
kind of like big boxes.
    [Laughter.]
    Senator Craig. Anyway, having said that, you talk about the 
legal challenges, the good news, the bad news, and the bad 
news/good news----
    Mr. Phillips. Yes.
    Senator Craig. Walk us through the ultimate legal 
challenges that you see that we can be players in that continue 
to allow the technology and the industry to move in the 
directions we want it to move in.
    Mr. Phillips. All right, well, one of the biggest things is 
just, just, you know, who owns the CO2 once it goes 
into the ground, who's going to be liable if it starts to leak 
back out----
    Senator Craig. The Big Belch, in other words.
    Mr. Phillips. Yeah, or it finds a stray oil well that we 
didn't know about, and it starts coming up there, are you 
liable to pay money? Or are you just liable to fill up the 
hole? Do you have to capture additional CO2 
somewhere else and put that in the ground?
    You know, and then there's, you know, the usual silly 
things that you're going to expect, that somebody's, you know, 
rose bushes die, and they attribute that because of the, you 
put CO2 in the ground 50 miles away. Those kind of 
things need to be addressed also.
    Senator Craig. Those are serious things, at the same time, 
as a percentage of the whole, what percent of the impediment 
exists in those legal questions today? In your mind?
    Mr. Phillips. It's enormous, it's hard to overstate it. Two 
things that bankers and insurance companies don't like is 
uncertainty. Right now, that's all we have when it comes to 
geologic sequestration of CO2, because we haven't 
done very much of it, nobody really knows what could be the 
consequences. Nobody knows what the rules are. If I put 
CO2 underground in the ground that I own, and it 
goes over to the ground you own, do I have to pay you money for 
that? Right? I mean, all of these things have to be taken--EOR. 
We've got the pipeline up in North Dakota, they allow 1 percent 
of sulfur in that CO2. The pipeline down in Texas, 
they allow 10 parts per million. What's the basis for those 
two? What am I supposed to design my plant to be able to do? We 
need some----
    Senator Craig. So you need uniformity.
    Mr. Phillips [continuing]. We need some uniformity.
    Senator Craig. You need certainty.
    Mr. Phillips. We just need to know what the rules are going 
to be.
    Senator Craig. Legal structure brings that.
    Mr. Phillips. Right.
    Senator Craig. OK.
    Mr. Phillips. I think that the liability question, I think 
if we're going to ask power companies to put CO2 
underground for the public good, that we need to provide some 
kind of a mechanism to say, ``OK, if you follow the rules, and 
do this the way we want you to, you know, you're now exempted 
from liability after you've met all of those requirements.''
    Senator Craig. I want to thank Senator Dorgan in his new 
role as chairman of that subcommittee that he spoke of for 
funding sequestration R&D. I think that's extremely valuable as 
we continue to move this spectrum forward.
    Having said that, recently the Senate passed an Energy Act 
of 2007, and in that Act was a section related to carbon 
capture and sequestration demonstration project at the Capitol 
Power Plant. I looked at that and thought, ``Gee, that's a nice 
political feel-good.'' Is it realistic to take one of these old 
plants in the heart of a capitol city and practice any form of 
reasonable sequestration? Or carbon capture? Or is that simply 
a waste of money? Maybe that's a question too hard for you to 
go to.
    Where should we be doing this kind of R&D, other than in 
our Nation's Capitol. Out in Wyoming?
    Mr. Phillips. I know two Senators who would----
    Senator Craig. Jerry and Carl, I'm not going to let you off 
now----
    [Laughter.]
    Senator Craig. We put Jeff on the hook, why don't you 
respond to that? The latter part of the question?
    Mr. Bauer. I appreciate the latter part, not the first 
part.
    Senator Craig. I'm sure you do.
    Mr. Bauer. I believe that the plan that we have going 
forward is a very solid plan. Because, as Jeff was talking 
about, some of the legal constraints, there's also the 
acceptance constraints. Part of the regional partnership issue 
is, getting the States--I mean, let's face it, this is done 
locally. We can decide here in Washington what we think is the 
right thing to do, but the people who have to put it to work 
and live with it are out there where they live.
    So, part of the regional partnership was both to collect 
the scientific and technical information required to ensure 
that this was right and safe in that scale, and to identify the 
places that it could be done, and it covers 97 percent of the 
country's most probable places, and power and industrial 
CO2 production, so it's covering a broad spectrum of 
opportunity, and to get the regulators, the State officials, 
the citizens, the academia of the State and region actively 
involved so they can understand it, so as this becomes law, and 
as it becomes regulation, they have already engaged in the 
process, and so we can continue to move forward, for those of 
us who got involved in applying CIRCLA and RICLA, we know we 
went through a decade of legal battles about doing things, 
because we didn't get people comfortable about what was being 
done, and there were tremendous battles.
    This is an important issue, to move it forward requires 
extensive large-scale demonstrations and scientific and 
technical work around that, but it also requires the work of 
the people in the area to understand what's going on, so that 
they feel comfortable and acceptable risk around this whole 
issue.
    So I think, the question you ask is really, we need to do 
it out in the States, and the States that have the highest 
probability of using CO2 capture are the ones that 
have substantial industrial CO2 generation, or power 
generation CO2, and do have reservoirs. In fact, 
that's what the regional partnerships represent, and have 
aggressively got companies to put money up.
    The regional partnerships don't just live off the largesse 
of the Federal dollars, there is a tremendous amount of 
investment from the private sector with them. So, I think we're 
getting a tremendous move forward in accelerating the process 
of acceptance and understanding how to do it legally right 
there.
    Senator Craig. Mr. Chairman, and Senator Domenici, the 
reason that I ask that question--while I understand sometimes 
we do things that are politically ``feel-goods,'' the reality 
is that siting some of these facilities is not unlike how we're 
siting new reactor generator facilities. The easier siting 
comes where they are, and where there is, in my opinion, a 
feeling of understanding on the part of the populace, as it 
relates to the need to site.
    Case in point, we had a company try to site a major coal--
it would have been a merchant generator, a major coal plant in 
Idaho, 2 years ago. Right by the rail, had its water, could 
have used Wyoming coal, and the State of Idaho said no. The 
people said no. Now, I won't suggest that it made the siting 
possibility, opportunity may not have been handled as well as 
it could have been, but the reality was, and it goes back to 
what Senator Dorgan is saying, there was a great opportunity 
here, but it probably occurs where it already is, from a 
standpoint of acceptance and understanding, and the issue of 
cleanliness, i.e. non-emitting, is paramount now, in the minds 
of most Americans. We've got to get this thing done, and the 
only way we're going to do it is in partnerships and investment 
to get us off from an 80 percent escalated cost. That's 
unacceptable.
    Thank you.
    The Chairman. Thank you very much.
    Senator Sessions has been waiting, why don't we go ahead 
and have you ask your question. Then Senator Tester, and then 
we have a vote at 10:35, at least that's what I've been 
informed, so maybe we can conclude the questions of these 
remaining two Senators, and then finish with this panel before 
we go to vote.
    Senator Sessions.

         STATEMENT OF HON. JEFF SESSIONS, U.S. SENATOR 
                          FROM ALABAMA

    Senator Sessions. The Economist Report of June 2, reports 
that coal produces 50 percent of America's electricity, 70 
percent of India's, 80 percent of China's, it's widely 
distributed around the globe, noting that China is adding coal-
fired, powered plants at a remarkable rate. Two 500-megawatt 
coal-fired power plants are starting up every week in China, 
which is each year, they're adding more than Britain has, 
total. So, coal is a real factor in everything that we must 
think about, as we consider electricity for the future.
    There was a book by, Mr. Chairman, I believe it's Jacquard, 
a Canadian who analyzed all of this, and global warming, and 
concluded that fossil fuels capture is the best way, long-term, 
for America, for the world, to meet our global warming, and 
energy needs. So, I don't know where we are. We certainly have 
a lot of coal.
    Let me ask you first, Mr. Bauer, if you have concluded in 
the next, say 20 years from today, if you produced clean coal 
with capture, and nuclear-generated electricity, what would be 
the relative cost of those two, do you have any idea?
    Mr. Bauer. I would submit that if the research that has 
been done, and the technologies that are coming forth, 
implement, in today's dollars, let's say, we would see, 
hopefully we'd be meeting our goals of maybe 10 percent to 15 
percent increase in electricity, assuming that the demand for 
electricity doesn't outstrip the supply, and then we get into 
market dynamics of supply and demand.
    I think the same thing is true on nuclear power, I happen 
to come from a nuclear power background earlier in my career, 
and both opportunities for power generation are substantial 
base load contributors that, up and running, keep chugging 
along and generating. So, for coal, CO2 capture at a 
decent price, and CO2 sequestration being understood 
and utilized, I think the prices will stay in a very marginal 
area, and we have plenty of sequestration and storage 
opportunity, according to the USGS reports, and our analysis of 
that.
    Senator Sessions. So, my, my, I guess a consumer goes and 
pays his bill, he doesn't expect a great difference between 
clean coal cost of electricity and a nuclear base load cost of 
electricity?
    Mr. Bauer. I think if you look--one of the problems that I 
question is a fact of materials availability. If you look at 
both GE's comments on the meeting with Hitachi, and merging to 
make power plants, they raise their price from the merger a 
year ago to now by 50 percent, all based on concrete and steel 
availability. That's an issue we're not talking about, but that 
is a big issue of building power plants, capturing 
CO2, and building nuclear power plants that is 
really going to drive that price up.
    Now, if we can get that back under control and balanced by 
rebuilding our capability to produce--a different issue, I 
know, Senators--then I think the prices can come back into 
operation and construction that are reasonable to what we 
experienced today, a little higher because of having to do 
additional things. The fact that we're down to about 20 percent 
of what original scrubber technology cost today, at this, the 
inflated dollars, should suggest we have the same opportunity 
to go forward with improved technology, and it becoming ever 
less expensive.
    Senator Sessions. One of the things I think we would need 
to ask, and maybe, Mr. Phillips would have an idea or any of 
the others, it seems to me that there are certain areas of the 
country more capable of storing CO2 than others. A 
Federal mandate that requires that, do you have any idea--is 
that true? Should there be any compensations for areas not able 
to do so?
    Mr. Phillips. It's certainly true that there is some areas 
that don't have good areas underground for storing 
CO2, unfortunately, my State of North Carolina is 
one of them, we'll have to send a pipeline over the Appalachian 
Mountains to find a good location, maybe we can send it all the 
way down to Alabama if you'll let us. Whether there should be 
compensation for that, I don't know, but I think it speaks to 
your first question, which is, we can't do it all with carbon 
capture from coal power plants, we can't do it all from 
nuclear, we can't do it all with renewables, there is no silver 
bullet, what we need is silver buck shot--we've got to try it 
all.
    [Laughter.]
    Senator Sessions. Mr. Chairman, I know your time, I'll 
yield back, thank you, sir.
    The Chairman. I think the vote is about half over, so let 
me move, go to Senator Tester.

          STATEMENT OF HON. JON TESTER, U.S. SENATOR 
                          FROM MONTANA

    Senator Tester. Thank you, Mr. Chairman.
    So that means your answer is going to have to be very 
concise.
    I think this is for Carl--the Future Gen project is a--
appears to be a pretty decent project, public/private 
partnership for zero emissions. It appears to be going slower 
than what I thought. Give me your perspective, tell me what you 
think on where it's at as far as moving along, and tell us what 
we can do to help push it along.
    Mr. Bauer. It was an easy question, at least.
    Senator Tester. See if you can do that in 15 seconds or 
less.
    Mr. Bauer. The Future Gen Project, actually, is moving 
along for a general coal-type utility project, pretty much as 
they normally do. So, it seems slow, but that is a real sense 
of what it takes to build these large plants. It has some 
conditional issues about finding the State and location to put 
the CO2 in, which has added to the timeframe. We're 
hoping that a selection of site will be completed by the end of 
the calendar year, and that by next year, assuming 
Appropriations and everyone agrees to go forward to the larger 
money about actual design and building, design work is going on 
right now, will continue on the schedule to still meet our goal 
of testing by 2012, and proving that sequestration works at 
large scale. How do we imperil that will also be proving the 
sequestration side for the regional partnerships.
    FutureGen also is to prove that the theory about capturing 
CO2 inexpensively from IGC, running hydrogen 
turbines which don't run anywhere today, all of the issues 
about gas cleanup and the economics will also be improved in 
the integration and balance of plants. Those are big challenges 
that are often lost in the discussion of CO2 capture 
that that FutureGen Project is also going to try to answer.
    Senator Tester. Is there anything we can do to push it 
forward, or do you think it's adequately moving the way it is?
    Mr. Bauer. I think the progress is being made in a very 
timely manner, I do think that, you know, the continued funding 
and recognition of funding will be there, helps the industry 
decide they want to put their shoulder to it and keep pushing, 
rather than kind of going along wondering if they should make 
the investment. I know that's a big challenge for the country.
    Senator Tester. Thank you, Mr. Chairman. We've got to go.
    The Chairman. All right.
    Let me thank all three of you, this has been very useful. 
We have one other panel that we will return to in about 10, 15 
minutes, and resume the hearing.
    Thank you, we're on recess for that period.
    [Recess.]
    The Chairman. Why don't we go ahead with the second panel. 
I apologize to everybody for the long delay. They had various 
problems on the Senate floor getting a second vote 
accomplished.
    This second panel, let me just introduce the people here.
    Mr. Don Langley, who is the Vice President and Chief 
Technology Officer with Babcock & Wilcox Companies in 
Barberton, Ohio.
    Mr. Andrew Perlman, who's Chief Executive Officer with 
Great Point Energy in Cambridge, Massachusetts.
    Frank Alix, who is Chief Executive Officer with Powerspan 
in Portsmouth, New Hampshire.
    Jim Rosborough, who's Commercial Director for Alternative 
Feedstocks with Dow Chemical Company.
    Bill Fehrman, who's the President of PacifiCorp Energy in 
Salt Lake.
    Thank you all for being here and why don't you each take 
about 5 minutes and summarize your main points. We will put 
your full statements in the record.
    Mr. Langley, go right ahead.

   STATEMENT OF DONALD C. LANGLEY, VICE PRESIDENT AND CHIEF 
TECHNOLOGY OFFICER, THE BABCOCK AND WILCOX COMPANY, BARBERTON, 
                               OH

    Mr. Langley. Chairman Bingaman, distinguished members, 
thank you for the honor to testify before you today. My name is 
Don Langley and I'm the Vice President and Chief Technology 
Officer for the Babcock and Wilcox Company, a provider of 
advanced pulverized coal boiler technology and all types of 
environmental control equipment for the electric power 
industry.
    I'm here today to talk about carbon capture and storage 
technology or CCS technology for use in the electric power 
industry. We and other technology providers are actively 
developing a variety of CCS solutions for coal power plants. 
While these multiple tracks require different development lead 
times, commercialization is not too far in the future. With 
appropriate policy, that is policy that does not pre-select 
winners, I believe our industry will deliver a variety of 
technologies for carbon management.
    Among other options, there are two in particular that I'd 
like to discuss. B&W is leading the effort toward 
commercializing oxy-fuel or what we call oxy-coal combustion 
technology for carbon dioxide capture. Starting this month we 
are running privately funded, large-scale oxy-coal tests at our 
30 megawatt thermal test facility in Ohio. We're also 
conducting a feasibility study with American Electric Power to 
examine retrofitting oxy-coal to an existing plant and we're 
working intensely with Saskatchewan Power, who seeks to build a 
new 300 megawatt plant, utilizing oxy-coal combustion for both 
power and enhanced oil recovery. The oxy-coal combustion 
approach also holds promise of near-zero emissions, including 
almost complete elimination of NOX, mercury, and 
SOx.
    Another area where we are actively working, is improving 
the efficiency of plants by raising steam temperatures. As with 
the rest of the industry, and really all across the economy, 
efficiency improvement pays dividends. B&W's goal is to 
increase efficiency such that CO2 emission levels 
for a new plant would be 30 percent below today's fleet, the 
average of today's fleet. This can help our cause in two ways.
    First, replacing older, least efficient plants in the 
existing fleet would allow us to continue to meet energy 
demands with less CO2 output. But I think even more 
interesting, this advanced process applied in conjunction with 
CCS technology will reduce the amount of CO2 needing 
to be captured, thereby lowering costs for carbon capture and 
improving total plant economics.
    Oxy-coal and efficiency gains are two examples of our 
technology initiatives and now I want to make a few points 
about deployment. MIT's future of coal report recommends 
building field demonstration projects that capture and store 
about one million tons of CO2 per year, with a 
projected cost share of $2 to $3 billion. This multiple project 
approach is then the first key enabling step leading to 
commercial-scale early deployment projects with roll-out of 
commercial projects with CCS then to follow. We agree with 
MIT's recommendations and this is what I would say is putting 
first things first.
    Why this is important can be seen in an example roll-out 
scenario. One deployment scheme, one that the NRDC is 
advocating consideration of, is a performance standard, whereby 
over a 10-year period, 10 to 15 percent of the power generation 
from coal is required to be from low emitting sources. The 
result would be avoidance of about 400 million tons per year of 
CO2, while still meeting rising energy demands.
    I calculate that if this deployment occurred as a new 
capacity, up to 100 new 660-megawatt plants would be required. 
The investment then would be about $300 billion. My point is, 
that to enable this type of investment, a solid technology 
platform must be in place. To do that, we must do first things 
first.
    Finally, the timing of this technology roll-out and 
managing expectations is crucial to ensuring long-term success. 
B&W believes large at-scale CCS-based demonstration projects 
can be on the ground and operating in the 2012 to 2014 
timeframe. We think this is consistent DOE-EPA efforts to 
enable geologic storage around 2012. We then project that we 
could be ready for a large-scale roll- out with commercial 
performance guarantees around 2018 to 2019 and offer serious 
carbon storage from coal plants beginning in, perhaps, 2020. I 
understand that this timeline will be disappointing to some, 
but the risk associated with an ill-conceived or rush initial 
deployment of CCS technology is time lost for successful 
storage efforts in the future, lower storage levels in the 
aggregate, and ultimately higher costs. We have to get the 
long-term program right and not rush the short-term learning. 
We believe if we proceed in a thoughtful and deliberate way, we 
as an industry, can and will deliver.
    Again sir, thank you for the honor of testifying today.
    [The prepared statement of Mr. Langley follows:]

   Prepared Statement of Donald C. Langley, Vice President and Chief 
    Technology Officer, The Babcock & Wilcox Company, Barberton, OH
    Chairman Bingaman, Mr. Domenici, and Members of the Committee: My 
name is Don Langley and I am the Vice President and Chief Technology 
Officer of The Babcock & Wilcox Company. The Babcock and Wilcox 
Company, headquartered in Barberton, Ohio is a provider of 
supercritical pulverized coal boiler technology and a leading provider 
of all types of environmental control equipment for the electric 
utility industry, as well as for the renewable biomass natural resource 
sector.
    I am pleased to testify before you today on critical aspects of 
delivering carbon capture and storage, or CCS technology for the coal-
based electric utility industry. It is well recognized that the 
utilization of coal is an important element of a national strategy to 
ensure energy independence. It is also well recognized that to achieve 
meaningful greenhouse gas emission reductions, a portfolio of 
technologies will be required, including clean coal, solar, nuclear, 
wind, and biomass to name a few. The power providers also need options 
within each of these technologies to suit their specific needs, such as 
fuel. We would advocate then that it is necessary to avoid legislative 
provisions that would explicitly or implicitly pick winners in this 
important competition. Given certainty on performance requirements for 
clean coal and a clear need for CCS, a free and open market with 
healthy competition stands the best chance to deliver technology in a 
cost effective manner.
    I would start with some overview points. B&W recognizes the value 
of striving for carbon neutral energy sources, understands the tasks 
before us to mitigate carbon emissions, and willingly accepts the 
challenge. We have invested over $100 million over the last five years 
to develop innovative technology paths forward. We, and other 
technology providers, are actively developing a variety of climate-
friendly solutions for coal power plants. While the multiple tracks 
require different development lead times, the commercialization 
trajectories are not too far out into the future. Substantial R&D 
support and incentives will be needed to attain the interim goal of 
getting at scale, first-of-a-kind plants on the ground. By ``at 
scale'', I mean plants capturing and storing something like one-million 
tons per year. It is our opinion that the pathway forward consists of 
establishing these at-scale field demonstration projects, followed by 
early deployment, commercial scale units with special considerations, 
such as incentives, all leading to a large scale rollout of clean coal 
with CCS. Whether this pathway is structured by policy or allowed to 
occur naturally, these important steps must by completed to enable the 
investment required to support a large scale rollout of new technology. 
We must do first things first, the large scale R&D, and not attempt to 
do second things first by moving directly to large project incentives 
for projects with high deployment risk. It is important that policy 
recognize these important steps, and with appropriate policy, our 
industry will deliver a variety of technologies for carbon management. 
That is, policy that does not pick winners and addresses first things 
first is crucial.
    B&W is pursuing a variety of carbon-friendly technologies. I would 
like to discuss two of them.
    B&W is leading the effort toward commercializing oxy-coal 
combustion technology for carbon dioxide capture. Oxy-coal technology 
utilizes nearly pure oxygen instead of air in the combustion process 
which then produces concentrated stream of CO2 that can be 
stored geologically or used for enhanced oil recovery (EOR). Starting 
this month, we are running large scale oxy-coal tests that we privately 
funded at our 30 MWth R&D facility. This work is being funded by B&W, 
American Air Liquide, EPRI and a group of ten interested power 
generating companies. Battelle is also supporting the project with 
input on geologic storage parameters. We are also conducting a 
feasibility study with American Electric Power to examine retrofitting 
oxy-coal to an existing plant; and we are working intensely with 
SaskPower in Saskatchewan, who seek to build a new 300 MW plant using 
oxy-coal combustion for power and enhanced oil recovery. In addition to 
capturing almost all the plant's carbon dioxide, the oxy-coal 
combustion approach also holds the promise of near zero emissions, 
including almost complete elimination of mercury, NOx and 
SO2 emissions. Insuring that R&D programs or commercial 
deployment incentives are not structured to pick winners at the onset 
will then allow us to continue to move this technology forward, further 
develop the compression and storage aspects and deploy it along side 
other promising technologies. We have every reason to believe that 
commercially deployed oxy-coal combustion systems will be cost 
competitive or less costly than IGCCs designs when IGCC systems are 
finally configured to capture CO2.
    Another area we are actively working is improving the efficiency of 
power plants. Efficiency improvements pay dividends in almost all 
scenarios. The aggregate efficiency of the existing coal fleet is 
nominally 31%. Increasing the temperature and pressure of the steam in 
a combustion plant increases the power generation efficiency. A modern 
ultra-supercritical combustion plant can achieve efficiencies on the 
order of 38 to 40%, thereby reducing CO2 output by 16 to 18% 
on a specific, pounds per megawatt hour basis. B&W has set the goal and 
identified the technology roadmap for driving combustion plant 
efficiency even higher, to 45 percent, using very high temperature 
designs which would reduce the CO2 produced per unit of 
energy by perhaps 30%. This can help our cause in two ways. First, 
replacing the older, least efficient plants in the existing fleet would 
allow us to continue to meet energy needs with less CO2 
output. Additionally, this very high temperature process in conjunction 
with CCS will reduce the amount of CO2 needing to be 
captured, lower the capital investment and the operating costs for 
carbon capture, benefit the overall plant economics, and justify 
accelerated implementation. We have been receiving some support from 
the DOE for this activity as the alloy materials required must be 
certified for public use and will be used by all the technology 
providers. To continue to develop this technology, we will need as an 
industry, to construct a materials test center that will conduct 
advanced, component based research for the shared benefit of all 
technology providers. This important R&D function is worthy of funding 
considerations and we will be soliciting for this support in R&D 
funding plans.
    These are two examples of the investment B&W is making to redefine 
Clean Coal Technology. We believe that MIT, as articulated in the 
Future of Coal report, has it mostly right with recommendations for 
extensive, at-scale field demonstration projects, each of which would 
capture and sequester about one million tons of CO2 per 
year. The at-scale project approach is the key enabling step that would 
lead to accelerated commercial scale early deployment projects, 
followed by a large scale rollout of plants with CCS.
    We need to do first things first. For example, NRDC is advocating 
consideration of a proposed performance standard approach whereby, over 
a ten year period, 10 to 15% of the generation from coal is required to 
be low emitting power. I calculate that, if this goal were to be 
attained by building new capacity, up to 100 new, 660MW plants would 
need to be built, representing an investment approaching $300 billion 
in today's dollars. This is a worthy goal as this approach would remove 
upwards of 400 million tons per year of CO2 from the sector 
emissions while still meeting rising energy demands. My point is that 
to enable this type of investment, a solid technology platform must be 
in place and we must do the first things first. We agree with MIT that 
only $2 to $3 billion would be required to fund this large scale R&D 
and one million tons of CO2 per year at-scale field 
demonstrations. The sooner we start, the sooner we can get to the point 
where we are storing carbon dioxide in earnest.
    Finally, the timing of this technology rollout and managing 
expectations is crucial, particularly if we are to ensure long term 
success. B&W believes large at-scale CCS based demonstration projects 
can be on the ground and operating in the 2012 to 2014 time frame. Note 
that this is consistent with the DOE/EPA efforts to establish geologic 
storage regulations in the 2012 timeframe. We then project that we 
could be ready for a large scale rollout with commercial performance 
guarantees around the 2018 to 2019 timeframe and offer serious carbon 
storage beginning in perhaps in 2020. I understand that this timeline 
will be disappointing to some. But, the risk associated with an ill-
conceived or rushed initial deployment of CCS technology could result 
in time lost for serious storage efforts in the future and in lower 
storage levels in the aggregate. We have to get the long term program 
right and not rush the short term learning. We believe if we proceed in 
a thoughtful and deliberate way, we as an industry can and will deliver 
the results that move our Nation towards meaningful energy security, 
work towards a worldwide reduction in carbon emissions, and minimizes 
the impact on our Nation's economy while contributing to international 
competitiveness.
    Thank you for this opportunity to testify.

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

  STATEMENT OF ANDREW PERLMAN, PRESIDENT AND CHIEF EXECUTIVE 
           OFFICER, GREAT POINT ENERGY, CAMBRIDGE, MA

    Mr. Perlman. My name is Andrew Perlman and I am Chief 
Executive Officer of Great Point Energy and one of its co-
founders. Thank you for the invitation to testify here today 
regarding recent advances in clean coal technology and its 
prospect for deployment at commercial-scale in the near future.
    As my testimony will explain, I believe Great Point 
represents a significant breakthrough in clean coal technology 
and we are on track to deploy our plans at commercial-scale in 
the next few years. So I'm here to talk about Great Point 
Energy and the technology that we have developed, the catalytic 
gasification technology that we have developed, to convert low 
cost coal and also petroleum coke and even biomass into 
pipeline quality natural gas.
    We've got two major reasons for doing this. One is 
environmental and the other is economic. From and environmental 
standpoint, we can take the dirtiest of all commercial fuels 
and convert it to the cleanest of all commercial fuels. From an 
economic standpoint, we believe that we can manufacture natural 
gas for much less than it sells for in the industry. In fact, 
we were going through our economics and we actually hired 
Nexent, which is a division of Bectal to do a full economic and 
engineering analysis of our technology. All the numbers I'm 
going to present today come from Bectal. I was going over them 
with Secretary Bodman a couple months ago. One of the things 
that he pointed was that given the increase recently in, or 
over the last few years, in the cost of both L&G imports and 
also new natural gas exploration and production, we can 
actually be the lowest incremental cost of new natural gas in 
North America.
    It is also, the other benefit, that there's virtually 
unlimited resources and reserves available. We can build 
gasification plants in places like Wyoming and Montana today, 
and still be building plants 100 years from now without running 
out of reserves and not have any of the exploration or 
depletion risk that's inherent with natural gas exploration 
today.
    Unlike many of our competitors, which have focused on 
licensing strategies, at Great Point our strategy is to build, 
own, and operate gas-production facilities ourselves, in close 
proximity to both coal mines and oil refineries. We think this 
is important because, while there's been a lot of discussion 
about natural gas over the last few years, there haven't been a 
lot of shovels in the ground. So we think that it's very 
important, that if we want to be able to meet the aggressive 
timeframes that we've set out, that we make sure that we're 
leading the charge.
    But we're not doing it alone, we are working together with 
some significant energy companies and over the next few months 
we'll be making announcements of developments that we plan with 
some of the largest energy companies in this country.
    Well, we're a new a company, we think that we're also 
extremely well positioned to be able to develop the technology. 
We're backed by some of the leading venture capital, in fact, 
we think the leading venture capital firms in the country, 
groups like Kleiner Perkins, Draper Fisher Jurvetson, Advanced 
Technology Ventures, and Vinod Khosla, who you might have seen 
testify here in the past.
    I also think we've attracted an extremely experienced 
management team, people like the former VP of Technology for 
Bectal, who built two of the four largest coal gasification 
plants in the United States, as well as, recently, the Chief 
Process Engineer for Sasol, which operates the largest coal 
gasification plant in the world, just joined to run our 
engineering group.
    We have operating, successfully operating pilot plant 
facility in Des Plaines, Illinois and we've actually been 
running extremely successfully on Powder River Basin coal all 
summer. As I mentioned, we have economics, economic, complete 
economic and engineering analysis done by Nexant, a division of 
Bectal, and the economics are extremely compelling. We also, we 
haven't announced it publicly yet, but we also have a 
technology collaboration with one of the largest chemical 
companies in the world for technology development and scale-up.
    Just briefly talking about the technology and how it 
differs from what conventional gasification is and what you 
might think of it today in technologies from groups like 
Siemens and GE and Shell and Conoco. All of these traditional 
gasification technologies operate at extremely high 
temperatures, about 1,400 degrees Celsius. At these 
temperatures, it's so hot that the ash in the coal actually 
melts and forms something called slag and the slag is 
constantly eating away at the reactor walls.
    In fact, in order to have significant up-time and 
reliability, most of these manufacturers recommend that you 
have a second gasifier on standby so you can always be fixing 
one while you are running the other. They also require 
extremely costly equipment. In order to get to those 
temperatures, you need to inject pure oxygen, which means you 
have to freeze air down to near absolute zero to separate the 
oxygen from the nitrogen. Not only is that about 25 percent of 
the capital costs, but it's about 15 to 20 percent efficiency 
hit on these plants. Also, because they're at such high 
temperatures, you need to build them out of, a high temperature 
cooling equipment out of exotic materials, which raises the 
cost.
    But most importantly, all these technologies produce, do 
not produce pipeline-grade natural gas. They only produce 
syngas, which is a low-grade, a low-BTU fuel, which is not 
compatible to pipeline systems and particularly economic to 
move over long distances. You can upgrade syngas to natural 
gas, but in order to do that you have to have four chemical 
plants, all operating at very different temperatures, from near 
absolute zero all the way up to 1,400 and then back down again 
to convert the syngas into natural gas. So, you end up with 
very high complexity, a very low efficiency, high capital 
costs, low reliability, and high price for a million BTUs of 
the natural gas.
    So basically, the way that Great Point Energy solves this 
problem, is by introducing catalysts into the gasification 
system. So basically, coal or petroleum coke combines with 
steam in the presence of heat pressure and the catalyst to 
produce 99 percent methane or, basically, pure natural gas 
instead of low-quality syngas. All of the carbon dioxide, the 
ash, the sulfur, the trace metals, and the mercury are all 
safely removed as part of the gas clean-up process.
    The beauty of the situation is that all of the chemical 
reactions perfectly heat balance. So, actually the heat of, 
that's produced in methanation, which is an exothermic 
reaction, perfectly offsets the heat required for gasification, 
which is an endothermic reaction, meaning that we don't need to 
inject any oxygen into the system and we can operate at about 
half the temperature of normal gasification. So, we don't have 
any of the maintenance or liability issues. We don't have to 
have high temperature cooling equipment because we're not at 
high temperature. But most importantly, at the end of the day, 
we've produced pipeline-grade natural gas.
    The Chairman. Maybe you could sum up your testimony here, 
we're running over time.
    Mr. Perlman. Sure, sure. The importance of that, which was 
discussed earlier today, is that the places where you can 
sequester carbon dioxide are not usually, or easily sequester 
carbon dioxide, are not usually the places where you want to 
produce electricity, which is in the population centers. So, if 
you can generate a pipelineable fuel, you can do that mine 
mouth in places like Wyoming and Montana and Texas, where you 
actually, where you can easily sequester the carbon dioxide or, 
in those places, you can actually sell the carbon dioxide today 
economically for enhanced oil recovery.
    So, without any involvement from the Government whatsoever, 
you can actually, economically today, using the only proven 
carbon dioxide sequestration technology do that and then you 
can move the natural gas anywhere in the country where it needs 
to go.
    [The prepared statement of Mr. Perlman follows:]

   Prepared Statement of Andrew Perlman, President & Chief Executive 
               Officer, Great Point Energy, Cambridge, MA
    Mr. Chairman and members of the committee, my name is Andrew 
Perlman. I am the Chief Executive Officer of Great Point Energy, and 
one of its co-founders. Thank you for your invitation to testify today 
regarding recent advances in clean coal technology, including prospects 
for deploying this technology at commercial scale in the near future. 
Great Point is a advanced gasification technology company. Our 
technology allows us to convert coal directly into pipeline quality 
methane natural gas. As my testimony will explain, Great Point does 
represent a significant advance in clean coal technology, and we are on 
track to deploy our plants at commercial scale in the near future.
                        introducing great point
    Great Point does not fit the image of a start-up energy technology 
company. For one thing, we were able to get a running start. Our 
advanced gasification technology draws on--and includes many patented 
and significant improvements over--many years of synfuels research and 
development that the United States promoted and began to carry out as 
an urgent matter of national policy during the Energy Crisis of the 
1970s. This is one key reason why Great Point's technology will soon be 
ready for commercial deployment, even though our company is relatively 
new. We stand on the shoulders of giants, and are now reaching the 
heights they had hoped to reach until that 1970s version of the Energy 
Crisis passed, oil and gas prices fell, and coal gasification 
technology development languished. The founders of Great Point Energy 
launched our company in a sincere desire to make a major contribution 
toward solving the current energy and global environmental crisis, 
which this time seems unlikely to pass away quickly.
    Our company is based in Cambridge, Massachusetts. Because of our 
gasification technology--and, we like to think, the top management team 
we've attracted--we are fortunate to have gained the confidence, 
support, and funding of some of the greatest names in American venture 
capital, especially within the clean energy technologies sector: 
Advanced Technology Ventures, Draper Fisher Jurvetson, Kleiner Perkins, 
and Vinod Khosla. Our bench-scale tests, and our much larger sub-
commercial demonstration test facility, have operated successfully and 
on a sustained basis. We have met or exceeded all our performance goals 
for this stage of our technology development.
    We currently have thirty-five employees, nearly all of whom are 
highly experienced in developing, scaling, and deploying gasifiers, oil 
refineries, and power plants. We are ramping up rapidly now, raising 
significant amounts of additional funding for our large pre-commercial 
project, hiring additional employees and service providers, and 
selecting sites in the U.S. and Canada for our full-sized commercial 
projects, the first of which we expect will begin operating in 2011/
2012.
                     our technology & its benefits
    Most coal gasification efforts in North America have in common 
certain things: the recognition that our continent's coal reserves are 
vast; that coal is a key to our energy security and independence; that 
coal represents a relatively inexpensive source of energy; but that the 
traditional method of using coal--burning it--is inherently limited, 
dirty, and makes controlling carbon dioxide emissions extremely 
difficult and expensive, if not altogether impossible.
    Until now, the best-known coal gasification technologies have been 
pursued primarily for one particular application, namely direct 
production of electric power in what's called ``integrated gasification 
combined cycle'' or IGCC power plants. These technologies almost all 
operate at extremely high temperature; about 1400 degrees Celcius. At 
this temperature, the ash in the coal actually melts and forms 
something called slag. The slag constantly eats away at the reactor 
walls of the gasifier and leads to high maintenance costs and low 
reliability. In fact, a spare gasifier is typically required in order 
to achieve over 90% online availability of the plant so that one 
gasifier can be fixed while the other one is operating.
    In order to generate the heat in the system, conventional gasifiers 
require pure oxygen. This oxygen is generated in a plant which freezes 
air down to near absolute zero in order to separate the nitrogen from 
the oxygen. These air separation plants are extremely expensive--20% to 
25% of the capital cost and result in a huge efficency hit because they 
utilize so much energy and operate at vastly different temperatures 
from the high temperature gassifier. Finally conventional gasification 
processes yield synthesis gas, or ``syngas,'' which consists primarily 
of carbon monoxide and hydrogen gas instead of natural gas which 
consists entirely of methane.
    Chemically as well as commercially, the syngas from conventional 
gassifier is very different from natural gas. For one thing, few if any 
pipelines exist to transport syngas, whereas a highly integrated 
nationwide network exists to transport natural gas. This means that 
conventional gasification plants must be located next to power 
production facilities and near major population centers. As a result 
solid coal must continue to be transported across the country to these 
facilities at high cost. The combination of conventional gasification 
technology with power plants designed to burn the hydrogen and carbon 
monoxide they produce is called IGCC or Integrated Gasification 
Combined Cycle. The plants are highly complex and very expensive.
    The syngas from conventional gasification cannot be converted to 
pipeline quality natural gas without the addition of multiple complex 
chemical plants and processes.
    Further, with conventional gasification technologies, unless 
additional steps are taken essentially all of the carbon that started 
out in the coal will end up in the atmosphere as CO2. In 
order to remove CO2 for capture and eventual storage or 
sequestration, conventional gasification technologies require--in 
addition to the capital and operating expense of the oxygen plant--the 
further capital and operating expense of a so-called ``shift reactor.'' 
The shift reactor is a separate facility in which the proportion of 
carbon to hydrogen in the syngas mixture is ``shifted'' to a hydrogen-
rich blend by injecting steam which converts some of the carbon 
monoxide in the syngas to carbon dioxide. The carbon dioxide is then 
available as a separate stream for potential capture and storage or 
sequestration.
    Many, if not most population centers in the U.S. are located in 
areas where carbon dioxide cannot easily be sequestered, but these are 
the locations that IGCC plants need to be built to provide electricity. 
Therefore it is going to be very difficult to actually sequester carbon 
dioxide from these plants, even if they are built with technology to 
capture a portion of the CO2.
    Great Point's technology is different--much simpler, more 
efficient, lower temperature, and less costly. With the help of a 
catalyst, we use a single reactor vessel to carry out three different 
chemical reactions, as a result of which we are able to convert coal 
directly into pipeline quality natural gas in our gassifier instead of 
syngas. Roughly 50% of the carbon in the coal is removed and captured 
as a pure pressurized stream of CO2. In addition to our 
offering a less expensive way to turn coal's energy into gas, our 
product--pipeline quality natural gas--is more useful than syngas. It 
can be transported anywhere through the existing natural gas pipeline 
system. Its use is not confined to the immediate vicinity of our 
gasifies, unlike syngas produced by conventional gasifies, which must 
be co-located with power generation facilities. Thus we can build our 
plants in locations where we can easily sequester carbon dioxide, and 
in areas with depleted oil wells actually get paid for doing so, and 
then ship our gas anywhere in the country through the nations robust 
pipeline system. And the gas we produce, which chemically is the same 
as natural gas, can be used in exactly the same manner as natural gas, 
and for all of the same purposes: not just power generation, but also 
heating, industrial uses, and chemicals production.
    Our process is less costly and more efficient than conventional 
gasification. Ours does not require a large and expensive air 
separation system, a separate shift reactor, or a methanator--the 
costly facilities and equipment that conventional gasification 
technologies require as ``add-ons'' in order to produce syngas, or 
isolate CO2 for capture, or convert syngas into SNG. The 
energy conversion efficiency of our process--that is, our efficiency at 
capturing the coal's energy in our gas--is higher than for conventional 
gasification, too. This higher efficiency has several benefits: (1) We 
don't need to integrate our gasification reaction with other major 
facilities and equipment, such as an ASU, shift reactor, or methanator; 
(2) we don't operate at the high temperatures of conventional 
gassifier; and (3) because we operate at lower temperatures, we also 
don't produce slag, which absorbs a great deal of non-recoverable 
energy in the form of heat (in addition to fouling equipment and adding 
to maintenance expense).
    Our potential for cost-effective and sensible CO2 
management is much greater than for conventional gasification 
technologies as well. In Great Point's process, CO2 in a 
separate and pure stream is simply a by-product of our producing 
pipeline quality SNG. Of course, the CO2 still needs to be 
compressed for shipment via pipeline to locations where it can be used 
for enhanced oil recovery (``EOR'') or otherwise stored or sequestered. 
That is true of any gasification technology--or, for that matter, any 
other technology that may allow CO2 to be captured, 
including proposed oxy-combustion and other post-combustion capture 
technologies, if they can be made to work. The difference is that Great 
Point's process does not require the capital investment or operating 
expense of any extra facilities or equipment to produce CO2 
as a separate, capture-ready stream. That makes it different from 
conventional gasification technologies and hoped-for post-combustion 
CO2 capture technologies alike.
    Finally, of course, like other gasification technologies, Great 
Point's technology offers the prospect of truly clean coal in a 
traditional sense. We will produce almost none of the sulfur, oxides of 
nitrogen, or mercury emissions of power plants that burn coal. Our 
emissions profile for these and similar pollutants should be as good 
as, if not better than, the emissions of a natural gas-fired power 
plant in almost all respects.
    Clean coal really is possible. Moreover, as I will discuss next, it 
is also imminent.
                         commercial deployment
    I recognize that what I've said here about Great Point's technology 
would be of purely academic interest to the Committee if our technology 
could not soon be deployed at full commercial scale. Timing, not just 
technology, is among your key concerns. I'm happy to be able to offer 
good news and encouragement on that front, too.
    As I mentioned at the outset, Great Point's technology has already 
been demonstrated successfully both at bench scale and at the much 
larger scale of our test facility which we operated over the past year 
at the Gas Technology Institute's test facility outside Chicago.
    We will next build a permanent demonstration facility which will be 
our final step before full commercialization. Our first commercial 
project operating on pet coke will be constructed in cooperation with a 
major Fortune 50 chemical company at a site we have already identified 
and which we are already designing and engineering.
    We have done a great deal of work for these commercial projects 
already, in addition to inventing, patenting, testing, and proving the 
gasification technology that they will rely on. For example, we have 
screened literally scores of potential sites for the location of our 
initial commercial projects, and have narrowed down our finalists for 
the first such project to about six sites. In addition to a siting 
strategy, we have developed and are now in the process of implementing 
both a partnering strategy and a project design and execution strategy, 
so that we may rely on investment-grade industrial partners and largely 
standardized project designs to help us achieve and sustain an early, 
efficient, and rapidly expanding commercial ``launch.''
    Our business model is focused on building, owning, and operating 
these commercial projects ourselves, in conjunction paid construction 
contractors and in partnership with our strategic industrial allies. As 
I mentioned at the outset, we expect our first project to begin 
producing revenue in the 2011/2012 time frame. By 2017--ten years from 
now--we plan to have at least ten revenue-producing projects in 
operation and sales revenues of over $3 billion as a company. Almost 
all will be at full commercial scale. Within a decade our goal as a 
company is to a material contribution of the North American natural gas 
requirements from coal and petroleum coke, and from biomass feedstocks 
as well.
                       great point in perspective
    I hope my testimony, the information available on our website 
(www.greatpointenergy.com), and whatever answers or additional 
information that I can provide in response to questions or further 
inquiries from Committee will reassure you that (1) our company, for 
one, does have a clean coal technology that represents a significant 
advance, and (2) commercial deployment of this technology is relatively 
imminent, not some far-fetched dream for the distant future.
    At the same time, I want to acknowledge three points. First, our 
company could not be where it is without the great technological 
innovations and inventions of the scientists and engineers who came 
before us. Those far-sighted predecessors of ours were encouraged and 
largely funded by far-sighted predecessors of yours, the men and women 
who served here in Congress and elsewhere in the U.S. government during 
the Energy Crisis of the 1970s. This goes to show that government can 
help. I know that the Chairman has drafted legislation under which the 
government would again contribute in a substantial way to basic 
research and development for climate-friendly new energy technologies 
that may help the global environment while also helping North America 
become more secure and energy independent. From what I understand of 
your effort, Mr. Chairman, I applaud it, and hope our company may serve 
as a useful example of the long-term public benefits and private sector 
``leverage'' that government-sponsored energy sector basic research may 
one day yield.
    Second, the advanced coal gasification sector is large, and the 
potential market, both domestically and globally, is huge. There is 
ample room for several useful and successful technologies in this 
field, and for many companies developing them. At GreatPoint, we simply 
intend to do an excellent job, and to do it as rapidly and on as large 
a commercial scale as may be reasonably possible.
    Finally, in this spirit, there are additional things that I believe 
Congress and the Administration could do that would be useful to us and 
other companies focused on clean uses of coal that would speed the 
development of clean coal technologies. These include a $0.50/Gasoline 
Gallon Equivalent production tax credit for the generation of natural 
gas from North American coal, petcoke, and biomass much along the lines 
of the credits available for ethanol production; as well as loan 
guarantees and grants for coal conversion to clean natural gas. In 
short, we believe the conversion of coal to natural gas is at least as 
compelling, if not significantly more compelling, than traditional coal 
gasification and also as important to the nations energy independence 
as ethanol. We simply ask that it be treated equally with these other 
technologies when government support is available. In addition, we 
believe that setting a price floor for natural gas produced from highly 
efficient gasification of domestic feedstocks below which government 
guarantees would kick-in, would provide the assurances to enable large-
scale, multi-billion dollar facilities to be rapidly deployed in the 
market without any substantial direct government incentives, unlike 
many other areas of the clean energy industry. My associates and I at 
Great Point would welcome the opportunity to discuss our technology and 
recommendations further with you and your staff.
    Thank you again for this opportunity to appear before you.

    The Chairman. Thank you very much.
    Mr. Alix, go, is it Alix, is that the right pronunciation?
    Mr. Alix. Thank you. Yes.
    The Chairman. Thank you.

 STATEMENT OF FRANK ALIX, CHIEF EXECUTIVE OFFICER, POWERSPAN, 
                         PORTSMOUTH, NH

    Mr. Alix. Good morning Mr. Chairman and members of the 
committee. Thank you, for being invited here to speak. My name 
is Frank Alix and I'm CEO of Powerspan Corp. Powerspan is a 
clean energy technology company headquartered in New Hampshire. 
I'm co-founder of the company and a co-inventor on several of 
Powerspan's patents.
    We've been in the business of developing and 
commercializing clean coal technology since 1994. In order to 
fund technology development, we've raised over $70 million from 
private institutional corporate investors. Our most significant 
clean coal technology success to date has been the development 
and commercialization of our ECO technology, which is an 
advanced multi-pollutant control technology to reduce emissions 
of sulfur dioxide, nitrogen oxides, mercury, and fine 
particles, in a single system.
    First Energy Corporation of Akron, Ohio, has been a major 
supporter, providing the host site for ECO commercialization 
activities as well as substantial financial contributions. Over 
the past 3 years, we've successfully operated a 50-megawatt-
scale, commercial ECO unit at First Energy's Burger plant in 
Shadyside, Ohio. This unit has demonstrated ECO has the 
capability of achieving emissions below best available control 
technology for coal plants and comparable to outlet emissions 
from natural gas combined cycle power plants.
    ECO also produces a valuable fertilizer product, avoiding 
the landfill disposal of flue gas desulphurization waste. 
Furthermore, the ECO system minimizes water use because it 
requires no waste water treatment or disposal. Commercial ECO 
cost estimates prepared by perspective customers and their 
engineers indicate that ECO capital and operating costs would 
normally be about 20 percent less than the combined cost of 
separate control systems required to achieve the comparable 
reductions. For a 600-megawatt plant, this equates to an annual 
cost savings of about $5 to $10 million.
    Although the utility industry has a conservative approach 
to new technology adoption, the environmental and economic 
advantages of our ECO technology has resulted in some 
significant commercial progress. Within the past year, First 
Energy announced the commitment to install an ECO system on its 
Burger plant, units four and five, an installation valued at 
approximately $168 million.
    Additionally, AMP-Ohio recently announced a commitment for 
ECO for its proposed 1,000 megawatt plant in Meigs County, 
Ohio. This commitment was driven in part by the promise of a 
new technology Powerspan is developing for CO2 
capture, which we call ECO2. The ECO2 
process is a post-combustion CO2 capture process for 
conventional power plants. The ECO2 technology is 
readily integrated with our ECO process and is suitable for 
retrofit to the existing coal-fire generating fleet as well as 
new coal-fired plants.
    Since 2004, Powerspan and the Department of Energy's NETL 
have worked together to develop the ECO2 process. 
The regenerative process uses ammonia to capture CO2 
in the flue gas. The CO2 capture takes place after 
other pollutants are captured. Once the CO2 is 
captured, the ammonia-base solution is regenerated to release 
CO2 in a form that's ready for geological storage. 
Pilot scale testing of our ECO2 technology is 
scheduled to begin in early 2008 at First Energy's Burger 
plant. The pilot unit will process a one-megawatt flue gas 
stream and produce about 20 tons per day of CO2, 
achieving a 90 percent capture rate. We plan to provide the 
captured CO2 for onsite sequestration in an 8,000 
foot well.
    First Energy is collaborating with the Midwest Regional 
Carbon Sequestration Partnership on the sequestration test 
project. This pilot program could be the first such project to 
demonstrate both CO2 capture and sequestration at a 
coal-fired power plant.
    The ECO2 pilot program provides the opportunity 
to confirm process design and cost estimates and prepare for 
large-scale capture and sequestration projects. Initial 
estimates developed by DOE, indicate that our ammonia-based 
capture process could provide significant savings compared to 
commercially available amnion-based CO2 capture 
technologies. Our own estimates, based on extensive lab 
testing, indicate commercially CO2 systems should be 
capable to capture and compress 90 percent of CO2 
from conventional power plants at a cost of about $20 per ton.
    Regarding prospects for deploying ECO2 at 
commercial scale, Powerspan and its commercial partners, 
Siemens and Fluor, are currently evaluating opportunities to 
deploy commercial-scale demonstration units to process 100 
megawatts of flue gas and produce approximately one million 
tons of CO2 per year for use in enhanced oil 
recovery or geological sequestration. A project of this size 
would be among the largest CO2 capture operations in 
the world and would serve to demonstrate the commercial 
readiness of ECO2 for full-scale power plant 
applications.
    With the anticipated success of the pilot unit, we would 
expect our first commercial demonstration project to begin 
operating in 2011 and full-scale commercial units to be 
operating by 2015, with commercial guarantees. Although large-
scale projects, such as taking ECO2 from a one 
megawatt pilot to a 100 megawatt commercial demonstration 
contains some risks, we believe the risk is manageable because 
equipment use in our process, absorbers, pumps, exchangers, and 
compressors, have all been used in other commercial 
applications. The technology in ECO2 is innovative 
process chemistry. Commercial application of this unique 
technology holds no special challenges that we can foresee, and 
therefore has a high probability of commercial success.
    We agree with the recent MIT study on coal that places a 
high priority on the commercial demonstration of CO2 
capture from several alternative coal combustion and conversion 
technologies, as well as CO2 sequestration at the 
scale of one million tons per year. However, such an 
undertaking will require substantial resources. The recently 
proposed 30 percent investment tax credit and $10 to $20 per 
ton CO2 sequestration credit is exactly the type of 
incentive needed and shows the Senate is prepared to provide 
the required leadership. It is important that such incentives 
apply to both pre- and post-combustion technologies and require 
that CO2 capture and sequestration be accomplished 
at a reasonably large scale.
    Additionally, in order to move large-scale CCS projects 
ahead as rapidly as possible, the incentives should to apply to 
retrofits at existing coal-fired plants, otherwise we'd need to 
wait for new plants to be built, which could unnecessarily 
delay the demonstration.
    I'll wrap up now because I'm a bit over. Thank you for the 
opportunity and I'd be happy to answer questions later.
    [The prepared statement of Mr. Alix follows:]

 Prepared Statement of Frank Alix, Chief Executive Officer, Powerspan, 
                             Portsmouth, NH
    Good morning Mr. Chairman and Members of the Committee. Thank you 
for the opportunity to share Powerspan's perspective on advances in 
clean coal technology. It is an honor to be invited here to speak. My 
name is Frank Alix and I am CEO of Powerspan Corp. Powerspan is a clean 
energy technology company headquartered in New Hampshire. I am a co-
founder of the Company and a co-inventor on several of Powerspan's 
patents.
    Powerspan has been in the business of developing and 
commercializing clean coal technology since its inception in 1994. In 
order to fund technology development, the company has raised over $70 
million from private, institutional, and corporate investors. Our most 
significant clean coal technology success to date has been the 
development and commercialization of our ECO technology, which is an 
advanced multi-pollutant control technology to reduce emissions of 
sulfur dioxide (SO2), nitrogen oxides (NOX), 
mercury (Hg), and fine particles (PM2.5) in a single system. 
FirstEnergy Corp. of Akron, Ohio has been a major supporter, providing 
the host site for ECO commercialization activities, as well as 
substantial financial contributions.
    Over the past three years, we have successfully operated a 50-
megawatt (MW) scale commercial ECO unit at FirstEnergy's R. E. Burger 
Plant in Shadyside, Ohio. This unit has demonstrated that ECO is 
capable of achieving outlet emissions below current Best Available 
Control Technology for coal plants, and comparable to outlet emissions 
from natural gas combined cycle power plants. ECO also produces a 
valuable fertilizer product, avoiding the landfill disposal of flue gas 
desulfurization waste. Furthermore, the ECO system minimizes water use 
because it requires no wastewater treatment or disposal.
    Commercial ECO cost estimates prepared by prospective customers and 
their engineers indicate that ECO capital and operating costs would 
normally be about 20% less than the combined costs of the separate 
control systems required to achieve comparable reductions. For a 600 MW 
plant, this equates to an annual costs savings of $5-10 million.
    Although the utility industry has a conservative approach to new 
technology adoption, the environmental and economic advantages of our 
ECO technology has resulted in some significant commercial progress. 
Within the past year, FirstEnergy announced a commitment to install an 
ECO system on its Burger Plant, Units 4 and 5, an installation valued 
at approximately $168 million. Additionally, AMP-Ohio recently 
announced a commitment to ECO for its proposed 1,000 MW plant in Meigs 
County, Ohio. This commitment was driven in part by the promise of a 
new technology Powerspan is developing for CO2 capture, 
which we call ECO2TM. The ECO2 process 
is a post-combustion CO2 capture process for conventional 
power plants. The ECO2 technology is readily integrated with 
our ECO process and is suitable for retrofit to the existing coal-fired 
generating fleet as well as for new coal-fired plants.
    Since 2004, Powerspan and the U.S. Department of Energy's (DOE) 
National Energy Technology Laboratory (NETL) have worked together to 
develop the ECO2 process. The regenerative process uses an 
ammonia-based solution to capture CO2 in flue gas. The 
CO2 capture takes place after the NOX, 
SO2, mercury, and fine particulate matter are captured. Once 
the CO2 is captured, the ammonia-based solution is 
regenerated to release CO2 in a form that is ready for 
geological storage.
    Pilot scale testing of our ECO2 technology is scheduled 
to begin in early 2008 at FirstEnergy's Burger Plant. The 
ECO2 pilot unit will process a 1-MW flue gas stream and 
produce 20 tons of CO2 per day, achieving a 90% 
CO2 capture rate. We plan to provide the captured 
CO2 for on-site sequestration in an 8,000-foot well. 
FirstEnergy is collaborating with the Midwest Regional Carbon 
Sequestration Partnership on the sequestration test project. This pilot 
program could be the first such project to demonstrate both 
CO2 capture and sequestration (``CCS'') at a coal-fired 
power plant.
    The ECO2 pilot program provides the opportunity to 
confirm process design and cost estimates, and prepare for large scale 
capture and sequestration projects. Initial estimates developed by the 
U.S. Department of Energy indicate that our ammonia-based 
CO2 capture process could provide significant savings 
compared to commercially available amine-based CO2 capture 
technologies. Our own estimates, based on extensive lab testing, 
indicate that commercial ECO2 systems should be able to 
capture and compress 90% of CO2 from conventional coal-fired 
power plants at a cost of about $20 per ton.
    Regarding prospects for deploying ECO2 at commercial 
scale, Powerspan and its commercial partners--Siemens, and Fluor--are 
currently evaluating opportunities to deploy commercial scale 
demonstration units that would process a 100-MW flue gas stream and 
produce approximately 1,000,000 tons of CO2 per year for use 
in enhanced oil recovery or geological sequestration. A project of this 
size would be among the largest CO2 capture operations in 
the world and would serve to demonstrate the commercial readiness of 
ECO2 for full-scale power plant applications. With 
anticipated success of the ECO2 pilot unit, we would expect 
our first commercial demonstration project to begin operating in 2011, 
and full-scale commercial units to be operating by 2015.
    Although large scale-up projects, such as taking ECO2 
from a 1-MW pilot to a 100-MW commercial demonstration, contain some 
risk, we believe the risk is manageable because the equipment used in 
the ECO2 process--large absorbers, pumps, heat exchangers, 
and compressors--have all been used in other commercial applications. 
The ``technology'' in ECO2 is innovative process chemistry. 
Commercial application of this unique technology holds no special 
challenges that we can foresee, and therefore has a high probability of 
commercial success.
    We agree with the recent MIT study on coal that places a high 
priority on the commercial demonstration of CO2 capture from 
several alternative coal combustion and conversion technologies, as 
well as CO2 sequestration at a scale of 1 million tons per 
year. However, such an undertaking will require substantial resources. 
The recently proposed 30% investment tax credit and $10-20 per ton 
CO2 sequestration credit is exactly the type of incentive 
needed and shows the Senate is prepared to provide the required 
leadership. It is important that such incentives apply to both pre-and 
post-combustion technologies, like ECO2, and require that 
CO2 capture and sequestration be accomplished at a 
reasonably large scale. Additionally, in order to move large-scale CCS 
projects ahead as rapidly as possible, the incentives should apply to 
retrofits at existing coal-fired plants. Otherwise, we would need to 
wait for new plants to be built with CCS, which could unnecessarily 
delay such demonstrations for several years.
    There is growing concern that the need to address climate change 
combined with the expanding use of coal presents an intractable 
problem, one where the tradeoff is between severe environmental or 
economic consequences. At Powerspan, we believe the necessary clean 
coal technology is near at hand, and the tradeoff need not be severe. 
Our ECO technology, which has the capability to produce a near zero-
emission coal-fired power plant, is commercially available, is being 
commercially deployed, and will set a new emission standard for coal-
fired plants. Our ECO2 technology, which is being developed 
for 90% capture of CO2 from conventional coal-fired plants, 
is on a well-defined path toward commercialization using currently 
available commercial equipment. The cost of wide spread deployment of 
CO2 capture technologies such as ECO2 appear 
manageable, particularly when one considers that post-combustion 
approaches such as ECO2 preserve the huge investment in 
existing coal-fired power plants, and avoid the need to replace a major 
portion of the power generating fleet.
    Thank you Mr. Chairman. I would be pleased to answer any questions 
that you or other Committee members may have.

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

 STATEMENT OF JIM ROSBOROUGH, COMMERCIAL DIRECTOR, ALTERNATIVE 
       FEEDSTOCKS, THE DOW CHEMICAL COMPANY, MIDLAND, MI

    Mr. Rosborough. Thank you chairman, Senator Domenici, and 
members of the committee. My name is Jim Rosborough from the 
Dow Chemical Company. Thanks for the opportunity to provide our 
views today on clean coal technologies and the practicality of 
their deployment. We appreciate your efforts in the search for 
environmentally friendly and economically sustainable energy.
    Today, I'd like to emphasize a few points on the subject. 
First, Dow is one of the world's largest chemical companies and 
is also one of the world's largest energy consumers. We convert 
the equivalent of one million barrels of oil every day in the 
chemicals, plastics, and electricity. The availability of low 
cost, price stable feedstocks is critical to our business and 
to our global competitiveness. Mr. Chairman, I can't emphasize 
this point enough. This is a strategic issue for the Dow 
Chemical Company.
    Second, we are confident that coal gasification is a viable 
way to enhance our nation's energy security and industrial 
competitiveness. It can also be an important part of the 
solution for climate change.
    Finally, to successfully implement industrial gasification 
at the right scale, we need a strong public-private partnership 
that will reduce the risk of investment and ensure the 
development of cost-effective carbon management techniques. The 
program we envision is doable now. Multiple commercial-scale 
industrial gasification plants that generate--sorry--that 
integrate the production of chemicals, plastics, fuels, and 
electricity can be a reality on the ground in this Nation 
within 10 years and they can greatly improve our energy 
security without breaking the carbon bank.
    Senator Domenici. Why 10 years?
    Mr. Rosborough. It takes a while to build a major-scale 
industrial complex, Senator. That's what we're talking about 
is, rather than a small demonstration facility. We're talking 
about major integrated sites.
    Thanks for the question, and we can talk more about it in a 
little bit.
    In 2005, our Chief Executive Officer, Andrew Liveress, 
appeared before this committee and said that we really want to 
invest in the United States, but that Dow has been discouraged 
from doing so recently because the United States has some of 
the highest and most volatile natural gas prices in the world. 
Since his testimony, natural gas and oil prices have remained 
high. In spite of Dow's improvements in energy efficiency, our 
feedstock costs jumped to $22 billion last year, up from $8 
billion only a few years prior.
    Clearly, we need a real solution to reverse this trend in 
the United States. Gasification can be a big part of the 
answer. It is versatile technology that can convert coal, 
biomass, wastes, or just about anything that contains carbon 
into virtually any product that society needs. A consortium of 
industrial companies, in partnership with the Government, is 
the best way to implement industrial gasification technology at 
the right scale and integrate all of the sectors that I just 
mentioned previously.
    There are two principle barriers that stand in the way of 
deployment. First, is the high capital costs of initial 
construction. Gasification plants are more than capital 
intensity of their conventional alternatives. A direct loan 
program or something to the equivalent nature is necessary, in 
our minds, to offset 50 percent of the capital cost of initial 
projects to attract private investors such as Dow Chemical.
    The second challenge is to manage the carbon footprint. Our 
initial analysis suggests, that by using up to 30 percent 
biomass and integrating the production of chemicals and 
plastics, along with carbon management techniques, we can cut 
the CO2 footprint of a gasification complex in half. 
Our experience tells us that the third and fourth plants built 
will be progressively more efficient and cost effective than 
the first. As operators gain experience and technology 
improves, the United States policy needs to reflect this.
    Mr. Chairman, we at Dow are ready and willing to 
participate in and even lead a gasification consortium in 
partnership with the Government and our industrial colleagues. 
We strongly believe that by working together, coal and biomass 
gasification can improve our Nation's energy security, 
revitalize our industrial competitiveness, and be an important 
part of the solution to climate change.
    Thanks for the opportunity to speak to today, and I'll be 
happy to address more questions.
    [The prepared statement of Mr. Rosborough follows:]

Prepared Statement of Jim Rosborough, Commercial Director, Alternative 
           Feedstocks, The Dow Chemical Company, Midland, MI
                               about dow
    Dow, founded in 1897, is America's largest chemical company. It is 
a diversified chemical company that harnesses the power of innovation, 
science and technology to constantly improve what is essential to human 
progress. The Company offers a broad range of products and services to 
customers in more than 175 countries, helping them to provide 
everything from fresh water, food and pharmaceuticals, to paints, 
packaging and personal care products. Built on its principles of 
sustainability, Dow has annual sales of $49 billion and employs 43,000 
people worldwide, with roughly half in the U.S.
    Dow has embraced a series of bold Sustainability Goals to address 
some of the world's most pressing economic, social and environmental 
concerns by 2015. One of these goals is to provide a sustainable, 
affordable energy supply worldwide while working to combat climate 
change.
    Dow operates at the nexus between energy and all the manufacturing 
that occurs in the world today. More than 96% of all manufactured 
products have some level of chemistry in them. As the premier chemical 
producer and one of the world's largest and most efficient industrial 
energy users, no one has more at stake in the solution--or more of an 
ability to have an impact on--the overlapping issues of energy supply 
and climate change than we do.
    Dow is uniquely positioned to continue to innovate concepts that 
lead to energy alternatives, less carbon-intensive raw material 
sources, and other products and solutions not yet imagined. This is an 
imperative for Dow, since our purchase of oil and natural gas accounts 
for nearly 50% of our costs. Last year, we paid $22 billion for the 
energy and feedstocks we needed, versus $8 billion in 2002. In just the 
second quarter of this year, these costs exceeded the prior quarter by 
$700 million.
    Dow is working aggressively on this problem, leveraging the 
strength of our laboratories around the world, to achieve technological 
breakthroughs that will help solve the greenhouse gas and energy 
challenges. Most recently, on July 19 we announced a world-scale 
project in Brazil that will turn sugar cane ethanol into plastic. It's 
a first-of-a-kind facility; it's renewable; and it's energy efficient, 
as we will use the leftover bagasse from the sugar cane to generate 
electricity. The project demonstrates Dow's role as a technology 
integrator, as well as the opportunities we have to drive forward our 
strategic growth in a way that fully supports our sustainability 
commitments.
    In addition, we:

   Pioneered the use of soybeans in the manufacture of high-
        quality plastic foam used in automobiles, office and home 
        furnishings, and other products.
   Recently announced Dow will make aircraft de-icing fluid 
        from glycerin, a by-product of biodiesel processing.

    Other sustainable energy inventions are on the horizon. For 
example, we are developing new roofing materials that convert solar 
energy to electricity, a project the Department of Energy has chosen to 
jointly fund because of its promise.
    In addition to our technology advancements, we are calling for 
strong government action on climate change, energy efficiency, 
conservation and security of supply. As a member of the U.S. Climate 
Action Partnership (USCAP), we are encouraging Congress to promptly 
enact mandatory, market-based climate legislation.
    We have been recognized as leaders in energy efficiency and are 
believers that improved conservation offers the greatest prospect to 
reduce carbon dioxide (CO2) and other greenhouse gas 
emissions.
    We have also made real progress in this area.
    In 1994, Dow made a public commitment to sustainability. We pledged 
then to improve our energy efficiency 20% by 2005. It was an ambitious 
goal--far greater than other heavy industries--and the fact that we 
achieved a 22% improvement is a great source of pride to our company 
and our employees, not only because of the reduction in our energy use, 
but because we did it profitably. We invested roughly $1 billion 
dollars and saved nearly $5 billion, which we believe is a very good 
return on our investment.
    During this period we saved 900 trillion Btu, enough energy to 
power all the homes in California for a year.
    Since 1990, we have improved our energy intensity by 38% and 
reduced our absolute greenhouse gas emissions by more than 20%, a level 
that exceeds Kyoto Protocol targets. We believe there is more to do, 
and have set a further goal to reduce our energy intensity by another 
25% by 2015.
    This relentless dedication to energy efficiency and our 
achievements is evidence that we know how to optimize the footprint of 
our existing assets and improve the efficiency of succeeding 
generations of technology.
                           why gasification?
    Industrial gasification provides technologically prudent yet 
flexible paths to a lower carbon future and greater U.S. energy 
security, as it would help the country diversity with abundant, 
domestic energy resources while helping address the high cost we and 
other manufacturers pay for raw materials.
                          about the technology
    Industrial gasification refers to the process of producing 
synthesis gas (syngas), a mixture of hydrogen and carbon monoxide, from 
a wide variety of raw materials, including coal, petroleum coke, 
industrial and municipal wastes, and other carbon-containing streams. 
Syngas is a highly efficient, highly versatile intermediate that can be 
converted to electricity, transportation fuels, chemicals or plastics--
or a combination of any of these products, in what as known as 
polygeneration (Figure 1, below*).
---------------------------------------------------------------------------
    * Figure 1 has been retained in committee files.
---------------------------------------------------------------------------
    Gasification technology can also be utilized to convert a wide 
range of biomass--plant matter, wood waste and crops--to energy and 
chemicals, replacing hydrocarbon fuels and feedstocks and reducing 
overall emissions of CO2. Additionally, it can turn high-
volume waste streams (e.g. plastics, municipal solid waste) into 
strategic fuel and feedstock sources.
    By innovatively combining bio-based materials with high-energy 
materials such as coal, wastes streams that are otherwise ``non-
recyclable'' (or only mechanically recyclable) can be converted into 
useful virgin materials, achieving a closed-loop, ``cradle-to-cradle'' 
life cycle for virtually any chemical or plastic.
                               challenges
    Capital Costs.--Even a ``small'' gasifier is a complex piece of 
equipment. Multiple gasifiers and related unit operations (i.e. an 
oxygen plant) are typically required, resulting in high capital costs 
relative to other technologies. A coal to liquids (CTL) gasification 
plant requires some three to four times the capital of a comparable oil 
refinery.
    Lack of Experience.--While gasification technologies have been 
around since the early 20th century, relatively few in the chemical or 
fuel industries have hands-on experience, contributing to the 
perception that gasification carries a greater-than-average technology 
risk. However, the operational experience to date provides evidence 
that a syngas platform could be a viable way to produce chemicals, 
plastics and fuels. Eastman Chemical in the U.S. and Sasol in South 
Africa are currently practicing coal-based chemistry on a commercial 
scale. This evidence of viability should give us confidence that larger 
scale deployment is achievable.
    CO2.--A globally-consistent carbon regulatory scheme is 
needed to create a stable long-term investment climate for gasification 
projects. Carbon capture and sequestration is arguably the most needed 
and widely acceptable technology solution for CO2 emissions 
control. Financing the development of the sequestration technology and 
infrastructure should be a priority for government investment. 
Gasification plants using hydrocarbon feedstocks, with their 
concentrated CO2 exhaust streams, are well suited to a 
national sequestration program as it develops. Economically attractive 
uses of CO2, such as enhanced oil recovery, should be 
encouraged.
    Co-gasification of biomass and wastes can help to reduce 
consumption of hydrocarbon feedstocks and overall CO2 
emissions. Some studies have shown that biomass can be co-gasified with 
coal at a rate up to 30% of total input.
    With industrial gasification, a significant portion of the carbon 
will find its way back into the supply chain as useful product. Carbon-
based products such as carpeting, water and sewer pipes, building 
insulation, packaging and automotive components can all be derived from 
either the naphtha co-product of a CTL plant, or directly from the 
syngas.
                               dow's plan
    We congratulate the committee and the Senate for its recent passage 
of an energy bill to improve U.S. energy security. But we respectfully 
submit that more needs to be done, particularly on the supply side.
    Our search for alternatives to the feedstocks we use currently have 
led us to believe that industrial gasification technology is mature and 
scaleable, could greatly improve America's energy security, and that 
building a full-scale plant of this kind in the United States can best 
be accomplished through a public/private partnership. We have expressed 
an interest in leading a consortium in the U.S. to demonstrate the 
technology on a commercial scale (approx. 80,000-100,000 barrels/day).
    Raw material feedstocks to produce syngas are abundant, present 
throughout the United States, and available at low costs. However, the 
major hurdle for any such plant in the U.S. is the high capital cost 
and obtaining financing. The promise of syngas plants will matter 
little without the right policy and incentives. Financiers are hesitant 
to provide the capital needed for a facility of the size needed to 
prove its worth.
    That is why we believe the federal government must dramatically 
increase its commitment to the development of a syngas infrastructure. 
Even with oil prices where they are today, the payback period deters 
private entities from building these plants (Chart 1*).
---------------------------------------------------------------------------
    * Charts 1-2 have been retained in committee files.
---------------------------------------------------------------------------
    The government needs to jump start a public-private partnership to 
develop a syngas industry by providing a focused capital investment, 
enacting stable policies and permitting the military to enter into 
long-term off-take agreements. Loan guarantees and tax credits alone 
won't make this happen.
    Based on our analysis, direct government loans covering up to 50% 
of the cost of a few early-mover projects seems to be what is needed to 
demonstrate viability (Chart 2*). We remain open to comparable 
alternatives.
    Our view is that absent a scaleable solution like industrial 
gasification, which brings a range of benefits, the U.S. over time will 
become a bit player in the petrochemical industry. Without significant 
U.S. action to reduce demand, increase supply and provide alternatives, 
the center of gravity of the petrochemical industry, and its downstream 
production, will shift to the Middle East, Africa and Asia. This 
movement has already begun. In the last two months alone, Dow alone has 
announced joint ventures totaling around $30 billion in these areas. 
More than 10,000 direct and 60,000 indirect jobs will be created--many 
of which could have been created in the United States, but for the high 
cost of energy, particularly natural gas, a commodity that, unlike oil, 
is regionally, rather than globally priced.
    Global competitors, integrated to low cost, often stranded 
feedstocks will be able to land competing products in the U.S. at a 
natural gas-equivalent cost of roughly half the U.S. gas price. The 
U.S. must continue to drive demand reduction through energy efficiency, 
increase domestic oil and natural gas production, and promote 
alternative and renewable forms of energy and feedstock. Syngas from 
coal, biomass or a combination of the two is a potential low-cost 
alternative to the high and volatile cost of natural gas, gas liquids 
and petroleum byproducts that are the basic building blocks of the 
modern chemical industry.
    We expect that with the government's assistance, we--in partnership 
with others--would prove the worth of a U.S. syngas industry.
    Syngas can be converted to chemicals and plastics as well as 
electricity and transportation fuels. With it, Dow can make virtually 
all of the products we currently manufacture. Coal is important because 
its abundance and established supply chain make it most capable of 
meeting syngas needs on a scale that will be economically meaningful.
                            carbon benefits
    Dow fully understands that we must live in a carbon-constrained 
world. And we support Congress' desire to improve the carbon efficiency 
of coal technologies. The CO2 must be managed. We agree with 
many members of this committee that in the near term, carbon capture 
and storage (CCS) should be developed to ease the U.S. transition from 
a fossil fuel-based energy economy to a low-carbon paradigm and 
eventually a zero-emissions future.
    Industrial gasification plants will help demonstrate options for 
CCS. Gasification of hydrocarbon feedstocks produces relatively pure 
CO2 streams, which can be used for economic purposes--
enhanced oil recovery or CCS. But these are not the only ways to limit 
atmospheric CO2 emissions.
    Our involvement in the gasification process (a chemical process) 
offers another way to maximize the use of CO2. The chemicals 
we make bind the carbon into useful products like plastic (Figures 2-
4*).
---------------------------------------------------------------------------
    * Figures 2-4 have been retained in committee files.
---------------------------------------------------------------------------
    Our initial analysis suggests that were a syngas plant to run on 
30% biomass, as experts tells us is possible, and were we to make 
products from the plant's feedstocks, we could bring the CO2 
footprint of a CTL plant down by about half (Figure 4).
    Further, we expect that through this consortium with other 
stakeholders, relying on experts such as those here today and our 
history of optimizing the chemical process will assure carbon 
efficiency improvements.
                            coal-to-liquids
    We've heard on both sides of the Capitol from members of both 
parties that coal must remain a key part of the U.S. energy mix and 
that any ultimate climate change policy must require a ``Manhattan 
Project'' for coal. The question is how to use coal in a carbon 
constrained world. In other words, how do you grow coal without 
breaking the carbon ``bank''? We submit that one of the best ways is 
through coal gasification.
    Dow believes we can participate in a coal-to-liquids plant and that 
doing so will improve its carbon footprint, as stated above.
    Initially, these plants are likely to run mostly on coal (Figure 
3). Over time, their operators will gain experience and the facilities 
will become more efficient, reducing their greenhouse gas emissions. 
Biomass will be increasingly used, further reducing greenhouse gases. 
And by utilizing sequestration in such a setup, there can be a net 
reduction in greenhouse gases compared to an oil refinery of comparable 
size (Figure 4).
    Dow has announced its intent to form a joint venture in China to 
build coal-to-chemical plants, which are similar to CTL facilities. We 
would like to explore this opportunity here if the capital cost and 
carbon footprint hurdles can be overcome.

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

 STATEMENT OF BILL FEHRMAN, PRESIDENT, PACIFICORP ENERGY, SALT 
                         LAKE CITY, UT

    Mr. Fehrman. Thank you, Mr. Chairman. My name is Bill 
Fehrman and I am President of PacifiCorp Energy, which provides 
power to PacifiCorp's customers in Utah, Oregon, Wyoming, 
Idaho, California, and Washington.
    We are responsible for implementing the policies that will 
ultimately be decided through the discussions that we're having 
today and beyond. It's also important to note that we do not 
develop the technology, but we do have the requirement to 
justify the technology to our regulators, so that we can be 
seen as making prudent decisions on behalf of our customers.
    We are constantly examining different ways to provide 
generating resources to serve our customer's fast-growing 
demands, while at the same time, trying to meet the strict new 
environmental requirements that we have today and that we 
expect to have in the future.
    Supercritical pulverized coal technology is available today 
and emits, basically, the same amount of CO2 as IGCC 
technology. We've used supercritical coal technology as a 
consideration or a bridge, if you will, while new approaches 
are developed to burning coal, such as IGCC with carbon 
sequestration and capture capabilities.
    It's critical to understand that IGCC's technology and 
carbon capture are two completely different things and can be 
applied to different sorts of opportunities. For instance, as 
you know, IGCC gasifies the coal and then it runs through a 
standard combustion turbine, whereas carbon capture and 
sequestration essentially takes the CO2, separates 
it, compresses it, and injects it deep into the earth. Both 
IGCC and pulverized coal technologies can be compatible with 
carbon capture and sequestration, they are not one against each 
other.
    In our case, no outside body, for instance, tells Starbucks 
what it can charge for products or what costs it can include in 
its prices. That's not the case for a public utility such as 
PacifiCorp. Our regulators determine the rates that we can 
charge and most States only allow recovery on those costs that 
can be demonstrated to be prudent and undertaken at a very 
cost-effective manner.
    This structure, just by itself, does not encourage 
utilities to become technology developers. Instead, we purchase 
those technologies from vendors and it's their shareholders, 
not our customers or our rate payers who earn the rewards of 
the success of bear the cost of the failure.
    In evaluating any of these technologies, we ask ourselves 
three key questions. Is it commercially proven and reliable? 
Are the risks and costs comparable to other available 
technologies that we have in front of us? Will our State 
regulators allow recovery of reasonable and prudent development 
costs in our rates?
    With respect to the IGCC technology today, our answer to 
each of these questions is no. The four IGCC plants operating 
today are not large-scale, they have not consistently achieved 
capacity factors comparable to supercritical plants and they do 
not capture and sequester CO2. Much of the 
technology remains unproven and we have not received cost or 
performance guarantees from vendors that can give us reasonable 
assurance that we can meet the prudent cost recovery 
requirements that our regulators will demand. However, it's 
these unknowns that demonstrate why more research in this area 
is so critical and why this debate has to continue.
    Most of the information on IGCC is based on the use of 
higher heat content bituminous coal. We believe that one of 
DOE's highest priorities should be IGCC R&D with sub bituminous 
coals and pre- and post-combustion technologies for capturing 
carbon from both IGCC and pulverized coal-fired plants.
    Government support can clearly help direct the industry 
toward this higher risk investment and away from the default 
choice of natural gas. Support should include such things as 
accelerated depreciation, investment and production tax 
credits, R&D funding, public and private partnerships to 
develop and construct commercial-scale plants. In fact, in this 
regard, PacifiCorp was recently chosen as the Wyoming 
Infrastructure's partner to pursue a high altitude IGCC plant 
using Powder River Basin coal. I would also add that our 
existing Jim Bridger sits atop some of the most promising 
CO2 storage locations in the United States.
    Carbon capture and sequestration currently utilized it 
enhanced oil recovery must also fit into this picture, but it 
faces major challenges, as you've heard before from others. So, 
we're sure our Federal research, development policy dollars go. 
From our view, support the development of IGC plants with a 
focus on the most abundant coal types, i.e., there is a 
significant amount of coal that is available, particularly in 
the State of Wyoming that has a potential to solve many of our 
issues in the long-term, provide R&D funding for low-cost, pre- 
and post-combustion CO2 capture process for both 
pulverized coal and IGCC, and provide funding for the 
advancement of technologies that result in higher availability, 
increased performance and cost, and eliminate the liability for 
sequestering CO2, that many of us view is one of the 
most significant risks of this, going forward.
    In order to move us toward a low-carbon future, IGC 
technology must be economically competitive, reliable and more 
broadly applicable to the lower-ranked coals and higher 
altitude conditions that exist in many of our locations across 
the United States, but particularly in the West. Remember that 
a combined IGCC-carbon capture and sequestration power plant 
does not exist anywhere in the world today, yet many talk like 
it's readily available.
    As we debate our future energy policy, we must not lose 
track of these facts, and the economic impact of developing 
this technology.
    Our customers will pay for our decisions, and when they 
turn on the switch, they expect the lights to come on at a 
reasonable price.
    Thank you for the opportunity to be here, and I'd be happy 
to answer any of your questions.
    [The prepared statement of Mr. Fehrman follows:]

Prepared Statement of Bill Fehrman, President, PacifiCorp Energy, Salt 
                             Lake City, UT
    Thank you, Mr. Chairman for the opportunity to testify today 
regarding the electric utility industry perspective on the potential of 
integrated gasification combined cycle (IGCC) technology. My name is 
Bill Fehrman, and I am the president of PacifiCorp Energy, the power 
generation and supply division of PacifiCorp. PacifiCorp provides 
electric utility service in six states across the West--Utah, Oregon, 
Wyoming, Idaho, California and Washington. My comments today reflect my 
views and experiences in this industry and are not meant to represent 
the industry as a whole, although I believe our experiences are largely 
consistent with those of other companies considering investments in 
clean coal technologies.
                        background on pacificorp
    PacifiCorp's generation mix includes nearly every major resource 
available to our industry: coal, natural gas, hydroelectric, wind and 
geothermal power. Along with our sister company, Iowa-based MidAmerican 
Energy Company, we are the largest on-system utility owner of renewable 
electricity in the country through our corporate parent, MidAmerican 
Energy Holdings Company, and we are also looking to expand our nuclear 
capability.
         key considerations with regard to generation resources
    PacifiCorp faces an enormous challenge to meet the demands of our 
customers. On one hand, we must bring new resources on line to serve 
the fast-growing demands of our Utah-based Rocky Mountain Power system. 
At the same time, we must meet strict new environmental requirements, 
particularly in the Pacific Northwest. It is critical that we move 
forward in a way that does not expose our customers to undue risk.
    In determining our energy supply and resource acquisition 
strategies for next-generation technologies, we ask three key 
questions:

          1) Is the technology commercially proven and capable of 
        providing reliable power for our customers?
          2) Is the cost and risk of the technology comparable to other 
        available technologies?
          3)Will our state regulators support these projects and allow 
        recovery of reasonable and prudent costs of development to be 
        included in rates?
        utilities are not encouraged to be technology developers
    The answers to each of these questions must be in the affirmative 
in order for public utilities to invest billions of dollars in new 
technologies. However, at the present time with respect to IGCC 
technology, the answer to each of these questions is no. Utilities are 
largely agents of the customers we serve. We assemble and integrate the 
various elements of electric service--power generation or acquisition, 
transmission, delivery, and customer service--to provide our customers 
with the most reliable system possible at a reasonable price, while 
complying with all federal and state environmental policies that may 
exist.
    For the most part, utilities do not individually develop 
technologies; we purchase technologies and operate them. The reason 
this is true might not be immediately obvious, but it is important to 
understand. No outside body tells Starbucks what it can charge for its 
products or what costs it can include in its prices. That is not the 
case for public utilities. State and federal regulators determine the 
rates that utilities can charge, and state statutes limit the costs 
that can be considered for inclusion in rates. Most state statutes only 
allow costs to be included in rates if the utility can demonstrate that 
the actions that gave rise to the costs were undertaken in a cost-
effective manner, which is typically defined in terms of risk-adjusted 
least cost.
                      the role of state regulators
    Our state regulators are the consumers' watchdogs and use a premise 
of risk-adjusted least cost to ensure that only those costs that are 
prudently spent are recovered in rates. This structure does not 
encourage utilities to become technology developers. Those 
responsibilities lie with the vendor community, where the market 
provides greater potential rewards for successful innovation. 
Shareholders of these companies, not ratepayers, earn the rewards of 
success or bear the costs of failure.
    Neither utilities nor regulators have perfect foresight regarding 
the development of future technologies, future market conditions, or 
changes in environmental laws, but we make the best projections we can 
in our resource development decisions. We also appreciate that the 
American public is increasingly concerned with environmental issues 
generally and global climate change specifically. A significant concern 
as it relates to electric utilities is carbon dioxide, the byproduct of 
the combustion of fossil fuels. Although the primary focus has been on 
coal-based generation, since it produces more carbon dioxide per unit 
of electric energy than other fossil fuels, natural gas-fired 
generation also produces carbon dioxide emissions.
    For a number of years, PacifiCorp's integrated resource planning 
process has included an estimated cost of carbon dioxide of eight 
dollars per ton. This is based on the assumption that at some point in 
the future, Congress will establish some form of greenhouse gas 
emissions reduction program that will increase the cost of burning 
fossil fuels. However, the ``cost'' of carbon dioxide and the timetable 
for mandating carbon constraints are not known. This has led to 
significant uncertainty as PacifiCorp has attempted to acquire or build 
new resources to meet customers' growing needs. As a consequence of 
this uncertainty, PacifiCorp has focused on the addition of non-
dispatchable renewable energy and natural gas-fired generation. 
Unfortunately, this does not solve our need for new baseload resources 
to meet growing demand for energy.
    As state and federal legislative action related to mandatory 
greenhouse gas reduction programs move forward, we will seek to 
continuously update our assumptions and integrate these assumptions 
into our resource planning. In every case, we will seek to accomplish 
the same goal--providing reliable, affordable service to our customers 
in a manner consistent with our core ``Environmental RESPECT'' policy 
of using our resources wisely and protecting our environment for the 
benefit of future generations.
                        today's resource choices
    Today, electric utilities across the country are facing the same 
challenge. Reserve margins on the system decrease with each passing 
day, and it is unclear what the best fuel source is to meet the demands 
of tomorrow. Each energy resource option has positives and negatives:

    Coal is domestically available, reliable and affordable, but it 
also creates carbon dioxide emissions at a higher rate than the other 
predominant fossil fuel of choice, natural gas. There are increasing 
efforts at grassroots levels to block construction of new pulverized 
coal-fired plants, even ones equipped with state of the art emissions 
control technology that meet all current environmental regulations.
    Natural gas allows for plants that can be permitted and constructed 
relatively quickly and at relatively low capital costs compared to 
coal-fired plants. However, fuel prices are highly volatile and 
domestic resources and infrastructure is strained. Since 1990, the 
overwhelming majority of new electric generating capacity has used 
natural gas as its fuel, helping push gas prices higher for all uses. 
We also face increasing concerns that, for the first time ever, the 
United States will soon begin importing a substantial percentage of its 
gas supply from outside North America, furthering our dependence on 
foreign sources of supply.
    Nuclear power is non-carbon emitting and has relatively low fuel 
costs, but we still do not have a long-term solution to the used fuel 
issue. Nuclear is an attractive option to consider in a carbon 
constrained universe, but to date no one in the United States has put 
all the pieces together to begin construction of a next-generation 
nuclear generating resource.
    Renewables include a whole range of opportunities including wind, 
biomass, solar, geothermal, and small hydro. They provide emissions-
free, sustainable energy sources. However, the primary renewable source 
is wind, which is both intermittent and non-dispatchable. In spite of 
rapid growth in recent years, thanks to Congress' extension of the 
Section 45 production tax credit, non-hydro renewables still only 
provide less than two percent of the country's generation mix. We are 
proud to be an industry leader in integrating renewables into our fuel 
mix. However, many of the most suitable locations are already under 
development, and transmission costs are likely to increase 
substantially. Furthermore, as renewable portfolio standards mandate 
ever larger percentages of energy, additional sources of backup 
generation will need to be installed to provide the reliability 
necessary due to the intermittency of wind.
    Hydroelectricity is also an emissions-free renewable generation 
source, but we are unlikely to see new large-scale hydro facilities 
built in the United States due to concerns about impacts on fish, river 
systems, and some endangered species. Indeed, the West is experiencing 
significant pressure to remove existing hydroelectric dams. 
Nonetheless, we should explore ways to maintain the hydro resources we 
have in an environmentally responsible way, explore cutting-edge, low 
impact hydro technologies, and work to gain greater efficiency from 
existing facilities.

    Some refer to energy efficiency as a ``fifth fuel,'' and we agree 
that energy efficiency represents one of the best opportunities to both 
meet resource needs and near-term emissions reductions. We commend the 
Senate, and this Committee specifically, for passing a bipartisan 
package of energy efficiency requirements in this year's energy bill. 
However, efficiency improvements only help flatten the growth of the 
demand curve; they do not eliminate the need for new generation 
resources. Energy efficiency and renewables alone will not meet the 
electric energy needs of this country.
                             what is igcc?
    As others have testified before this Committee, IGCC technology is 
designed to combine a chemical gasification process with traditional 
combustion turbine based processes to generate electricity at 
comparatively high rates of efficiency and low emissions levels.
    While I know that members of this Committee understand the 
difference, I want to emphasize for the record that IGCC technology and 
carbon capture and sequestration are not the same thing. IGCC describes 
a highly integrated two-step process: (1) coal gasification to produce 
a gas-based fuel that can be burned in a combustion turbine; and (2) 
power generation. Carbon capture and sequestration is a potential 
complementary add-on to this technology that would convert the carbon 
in the synthetic gas to carbon dioxide, separate and compress it, and 
ultimately inject it deep beneath the Earth's surface, resulting in 
permanent sequestration.
                      is igcc a proven technology?
    Worldwide, there are four operational IGCC electricity generating 
plants with generation capacity of roughly 250 megawatts each. None of 
these plants captures or sequesters carbon dioxide. The two plants 
operating in the United States (in Florida and Indiana) were built with 
federal funding assistance as part of the Department of Energy's Clean 
Coal Power Initiative demonstration projects.
    IGCC is not a commercially viable technology at this time. No large 
scale, utility-size plant has been built, and much of the technology is 
unproven, which is why we have not been able to obtain price and 
performance guarantees from any vendors. With the technology unproven, 
with unclear costs, and with no guarantees from vendors, we are 
unwilling at this time to expose our customers to these risks. 
Furthermore, these plants have not consistently achieved capacity 
factors comparable to readily available supercritical pulverized coal 
plants.
    Moreover, most of the information on the operation of IGCC 
technology is based on the use of higher ranked, higher heat content 
bituminous coal or pet-coke. Lower ranked subbituminous and lignite 
coals with lower heat content and greater moisture content can be 
gasified, but at lower efficiency. The industry needs significantly 
more experience working with these coals, especially given the quantity 
of these types of coals in the Western United States.
    The application of IGCC at higher altitudes presents unique issues 
that must be addressed given that a large quantity of low rank coals 
are found in elevations that exceed 4,000 feet. At high elevation, the 
air pressure--and hence the density of air--is lower. The output of all 
combustion turbine-based resources, not just IGCC plants, is thus 
reduced at higher elevations. The output of a combustion turbine is 
reduced approximately 3 percent with every 1,000 feet increase in 
altitude. For a project operating at 5,000 feet (which would apply to 
much of PacifiCorp's generating fleet in the Rocky Mountain region), 
output losses would be 15 percent. In simple terms, this increase in 
elevation results in a reduction in output, although the capital cost 
is essentially unchanged. Relocating the facility to a lower altitude 
and moving the electrons by wire may seem a reasonable option, but this 
would move the generation away from many of the most potentially 
suitable carbon sequestration sites in the United States and would also 
require moving more coal by rail. It is important to note that 
supercritical pulverized coal plants do not suffer the same output 
losses at altitude and are therefore considered to be an excellent 
choice for this type of application.
    For IGCC to reach its full potential in the United States, the 
technology must be improved, with a particular emphasis on performance 
with lower ranked coals and especially at higher altitudes. Funding for 
this improvement through the Department of Energy and research 
institutions should be one of our country's highest energy technology 
priorities. Government support for IGCC development can help direct the 
industry toward this higher risk technology investment and away from 
the default choice of natural gas. This support can take the form of 
accelerated depreciation; investment and production tax credits; 
research, development and commercial demonstration funding; performance 
certainty guarantees; and public-private partnerships to develop, 
construct and operate commercial scale IGCC plants. In this regard, 
PacifiCorp Energy was recently chosen as the Wyoming Infrastructure 
Authority's partner to pursue a high altitude, IGCC plant in the state 
that is designed to use Powder River Basin coal, and we are together 
seeking this government support.
            comparing igcc and supercritical pulverized coal
    Based on our studies, vendor and engineering-constructor 
information, and recent bids, as well as information we have seen from 
other utilities at this time, a supercritical pulverized coal plant 
costs roughly 25-30 percent less than an IGCC plant. Moreover, 
supercritical pulverized coal technology is mature and reliable, 
whereas IGCC is still far from having acceptable performance 
parameters, particularly with regard to lower ranked coals and high 
altitude applications. It is also important to note that today IGCC and 
supercritical pulverized coal emit basically the same amount of carbon 
dioxide.
    Using traditional measures of prudence and cost-effectiveness, and 
given our current estimates of the ``cost'' of carbon dioxide 
emissions, supercritical coal technology is the clear risk-adjusted, 
least-cost choice at this time. Unfortunately, in our view, a number of 
states have imposed emissions reductions requirements that effectively 
prohibit the inclusion of electricity produced by supercritical 
technology. Furthermore, some states are requiring that IGCC have a 
carbon footprint equivalent to natural gas-fired generation. This 
course of action essentially would require implementation of carbon 
capture and sequestration. Though well-intentioned, adding this 
requirement to IGCC will further frustrate the development of this 
technology. While we do not believe this is sound energy policy, we 
must follow the laws of the states we serve.
    If regulators and policymakers eliminate pulverized coal technology 
from our generation mix, choices for baseload generation are 
effectively limited to natural gas in the near term, with IGCC and its 
attendant technology risks in the intermediate term and nuclear. 
PacifiCorp and MidAmerican Energy will also continue to add renewable 
energy resources such as geothermal, wind and biomass where cost 
effective, but these resources supplement rather than displace the need 
for traditional baseload resources.
    In our view, the most appropriate policy would be to encourage the 
deployment of supercritical coal plants, while continuing to study IGCC 
and other clean coal technologies. At the same time, given the large 
number of existing pulverized coal-fired power plants in the United 
States, it is critical Congress and the Department of Energy increase 
research and development support for pre- and post-combustion 
technologies that would facilitate development of commercially viable 
carbon capture technologies for pulverized coal generation.
    This policy would allow us to meet our growth needs now, provide 
multiple paths toward carbon sequestration, and require both power 
generators and state regulators to use cost-effective clean generation 
technologies as soon as they are available commercially.
     how does carbon capture and sequestration fit in this picture?
    Carbon sequestration has been a byproduct in the oil production 
industry in a process known as enhanced oil recovery in which carbon 
dioxide is mixed with oil under the Earth to enhance oil extraction. 
Carbon dioxide is captured and re-injected, and ultimately the carbon 
dioxide is permanently sequestered below the earth's surface. Enhanced 
oil recovery is a widely utilized and well established technology, 
although the use of carbon dioxide for enhanced oil recovery is very 
site specific. It is expected that the demand for additional carbon 
dioxide will increase as production from existing oil, using 
conventional means, declines and oil prices continue to remain robust. 
Unfortunately, the demand for carbon dioxide for enhanced oil recovery 
is significantly less than the amount of carbon dioxide that is 
expected to be permanently sequestered to meet long-term target levels.
    Applying this technology to the carbon dioxide emissions streams of 
fossil fuel-based electric generation represents a tremendous challenge 
for the United States and the world. The Electric Power Research 
Institute's February 2007 research paper, ``Electricity Technology in a 
Carbon-Constrained Future,'' demonstrates that successfully deploying 
carbon capture and sequestration technology provides the single largest 
``wedge'' of carbon emissions reductions that could be achieved by the 
electric utility industry in meeting a goal of reducing 2030 emissions 
levels to 1990 levels.\1\ However, broad commercial deployment of 
carbon capture and sequestration technology is the critical component 
of achieving long-term reductions in greenhouse gas emissions, both 
domestically and internationally.
---------------------------------------------------------------------------
    \1\ Electric Power Research Institute, ``Electricity Technology in 
a Carbon-Constrained Future,'' February 2007, p. 11.
---------------------------------------------------------------------------
    The recent MIT study, ``The Future of Coal,'' also endorses this 
course of action, stating: ``We conclude that CO2 capture 
and sequestration (CCS) is the critical enabling technology that would 
reduce CO2 emissions significantly while also allowing coal 
to meet the world's pressing energy needs.''\2\
---------------------------------------------------------------------------
    \2\ ``The Future of Coal: Options for a Carbon-Constrained World,'' 
MIT Interdisciplinary Study, March 2007, Executive Summary, p. x.
---------------------------------------------------------------------------
    The challenge of applying carbon capture and sequestration 
technology to electric power generation.
    Applying carbon sequestration technology to the electric power 
sector will present at least three major challenges compared to the 
more limited use of the technology in enhanced oil recovery:

          1) The volume of carbon dioxide that must be extracted from 
        all power plant emissions streams is orders of magnitude 
        greater than those captured in enhanced oil recovery processes. 
        A single 800-megawatt coal-fired power plant will produce 
        approximately 6.1 million tons of carbon dioxide annually, 
        compared to the approximately 5 million tons of carbon dioxide 
        used annually by the largest enhanced oil recovery projects.
          2) An entirely new energy infrastructure will need to be 
        built to compress and safely transport carbon dioxide to 
        appropriate geological formations and inject it deep beneath 
        the Earth's surface. The United States is fortunate in that we 
        appear to have the world's greatest carbon dioxide 
        sequestration potential. However, these formations are not 
        evenly distributed throughout the country. Fully developing a 
        system of permanent carbon dioxide geologic sequestration sites 
        will require the United States to build a vast interstate 
        pipeline system somewhat similar to the natural gas pipeline 
        system that has been created over the last 100 years. Injection 
        wells must be drilled several thousands of feet below the 
        Earth's surface. This will require massive investments in 
        commodities, industrial products and manpower.
          3) Carbon dioxide injection for these purposes is designed to 
        be complete and permanent, or nearly so. The goal of 
        sequestration is to remove carbon dioxide from the atmosphere 
        for centuries and in a manner that is as close to 100 percent 
        certain to avoid leakage. In addition to the physical 
        infrastructure that must be built to facilitate carbon capture 
        and sequestration, the federal government and the states must 
        develop a legal and regulatory framework to support these 
        investments. Until a regulatory permitting legal structure is 
        developed and the issue of liability risk is addressed, it is 
        highly unlikely that large-scale carbon sequestration can be 
        achieved.
                    research and development efforts
    More research and development is needed in a number of areas. 
Congress must establish regulatory and legal frameworks and remove 
other barriers to implementation in order to allow and encourage 
private sector entities to move forward with investments in these 
technologies and commercial-scale carbon sequestration.
    We recommend the following priorities:

          1. Provide additional and reliable financial support to 
        facilitate development of IGCC plants with a focus on those 
        locations and coal types that are the most abundant.
          2. Provide research and development funding for development 
        of low-cost pre/post-combustion carbon dioxide capture 
        processes.
          3. Provide specific development goals for the advancement of 
        IGCC technologies that focus on major components that will 
        result in higher availability, increased performance and lower 
        cost.
          4. Provide a regulatory framework in which captured carbon 
        dioxide is considered a commodity and not a waste/pollutant.
          5. Provide financial incentives for permanent geologic carbon 
        dioxide sequestration.
          6. Develop a regulatory framework for injection wells and 
        carbon dioxide pipelines.
          7. Develop regulatory and policy certainty to eliminate all 
        liability for sequestering carbon under scientifically-based 
        federal standards.
          8. Develop a regulatory and policy position that supports the 
        use of supercritical pulverized coal as a bridge until new 
        technologies are proven and can be commercially deployed.
                                summary
    Before IGCC technology can provide a critical path toward a low-
carbon future, it must be made more economically competitive, reliable, 
and more broadly applicable to lower rank coals and higher altitude 
conditions. Policy makers must understand, however, that combining a 
chemical process (gasification) with a mechanical process (coal-based 
power generation), and then capturing and sequestering the gasified 
carbon, is not simple and does not exist today anywhere in the world.
    Policy makers must also appreciate that our first obligation as 
public utilities is to provide reliable electricity supplies for all 
our customers and that deploying new technologies to reduce carbon 
emissions will not come without significant increases in cost for these 
customers. We share the desire of Congress and the American people to 
proactively take actions to reduce and avoid carbon dioxide emissions 
as much as possible and as quickly as possible. However, technical 
challenges remain and emission reduction programs must be designed with 
these realities in mind--not based on randomly chosen timelines or 
politically appealing slogans.
    Your committee has played a highly constructive role in holding 
robust examinations of these issues. We hope that all members of the 
Senate will take these facts into consideration in developing climate 
change legislation. Utilities such as PacifiCorp face growing demand 
for energy, and we must build some type of resource to meet this 
demand, as we have an obligation to serve. It is critical that as we 
continue to debate the future of energy supply for the United States, 
we don't forget our current customers, who expect to see a light come 
on when the switch is turned, while paying a reasonable cost to do so.
    Thank you. I would be pleased to answer any questions.

    The Chairman. Thank you very much.
    I'm informed Senator Tester's going to have to leave in 
just a few minutes, let me defer to him, and he can ask my 
round of questions, and I'll come along later.
    Senator Tester. Mr. Chairman, I want to thank you very much 
for that.
    I want to--we'll kind of jump around here a little bit, 
Frank--the technology you talked about can be retrofitted on 
existing coal-fired plants, correct?
    Mr. Alix. Correct.
    Senator Tester. You said that the cost is about $20 per ton 
of CO2?
    Mr. Alix. Correct.
    Senator Tester. Now, I know it varies on the coal, but just 
how much CO2 is produced from a ton of coal from, 
say Wyoming or Montana?
    Mr. Alix. We look at more, in terms of a 500-megawatt plant 
is going to produce about 4 million tons a year of 
CO2.
    Senator Tester. Four million tons a year?
    Mr. Alix. Regardless of the coal.
    Senator Tester. Right.
    Mr. Alix. You know, to a certain extent, the coal, the 
carbon and the heat content are pretty closely related to 
CO2 release.
    Senator Tester. OK, the size availability, it will fit on 
any size plant? The retrofit?
    Mr. Alix. We don't see any reason why not.
    Senator Tester. It's 90 percent efficient? On capture?
    Mr. Alix. We're at lab scale today, but our lab testing 
which directly correlates, we think, to our next commercial 
scale up shows 90 percent capture is very doable.
    Senator Tester. OK, so, and what's the cost--any idea of 
what it costs to retrofit a plant? Of the size you talked?
    Mr. Alix. You know, we generally look at this $20 a ton, 
about $10 a ton is capital cost for retrofit.
    Senator Tester. OK.
    Mr. Alix. We're in $500-plus dollars a kilowatt for the 
retrofit.
    Senator Tester. Five hundred a kilowatt----
    Mr. Alix. So, let me put in numbers maybe you can 
understand. For a base loaded plant, you know, we're maybe $200 
to $300 million to put it on a 600-megawatt plant.
    Senator Tester. OK, sounds good.
    Andrew, the technology you talked about that moves coal to 
natural gas, what's the sufficiency, BTU to BTU?
    Mr. Perlman. It's between--depending on the type of coal 
and the feed sock, between 68 and 72 percent efficient.
    Senator Tester. OK.
    Do you have a plant of any size?
    Mr. Perlman. We do. In Des Plains, Illinois----
    Senator Tester. That's right.
    Mr. Perlman [continuing]. At the Technology Institute.
    Senator Tester. What kind of production does it have?
    Mr. Perlman. It's relatively small, it's about 3 tons per 
day of Power River Basin Coal.
    Senator Tester. Right. But you don't see any problem with 
increasing that production up?
    Mr. Perlman. No, it's a, basically a fluid-bed reactor, 
it's basically a tube with no innards.
    Senator Tester. Gotcha.
    Mr. Perlman. So, you know, the scale-up of fluid-bed 
reactors has been pretty well understood and modeled for----
    Senator Tester. All right.
    Don, the oxy-coal process that you talked about--what is 
the cost per kilowatt, or megawatt or however you want to 
produce it, compared to a conventional plant now?
    Mr. Langley. I think the most relevant cost is we would say 
that it's between a 45 and 50 percent cost of electricity 
increase----
    Senator Tester. OK.
    Mr. Langley [continuing]. To use oxy-coal, over a plant 
without it.
    Senator Tester. OK. Is there additional water needs with 
your process?
    Mr. Langley. No, not particularly.
    Senator Tester. For cooling? Not, huh? OK.
    Mr. Langley. I don't think, I think so.
    Senator Tester. OK. Good.
    Jim, first of all, I want to thank you for supporting my 
amendment. It's interesting what an organic farmer can combine 
with Dow Chemical on policy, but I really appreciate Dow's 
vision on that.
    Mr. Rosborough. Thank you.
    Senator Tester. You talked about a public/private 
partnership. The amount of money that is being allocated at 
this point in time, is it doing any good at all? Is it heading 
in the right direction? If you were a person in a position that 
could make a decision on how the money were to be allocated to 
form these kinds of partnerships, how would you do it?
    Mr. Rosborough. Senator, I think as you know in your 
amendment, there was a call for approximately $10 billion worth 
of direct loans, which is--to us--a fairly reasonable start for 
roughly three polygeneration types of complexes. It's our 
belief that the integration of chemicals, plastics, electricity 
and fuels, is necessary to maximize the carbon efficiency, and 
therefore get after the environmental friendliness of the feed 
stock issues, as well.
    Senator Tester. OK. So, $10 billion is in loans and that's 
how you would--that's how we'd distribute it, is through a loan 
program?
    Mr. Rosborough. That would be a nice start, that's probably 
three major complexes. Our vision is, the first one would tend 
to be the most expensive and the least efficient, and by the 
time we get to the third one, we would have demonstrated 
improvements in both efficiency as well as technology.
    Senator Tester. Thanks.
    Finally, Bill, and I'll wrap this up very quickly, you 
talked about the economic impact of developing the technology.
    Mr. Fehrman. Right.
    Senator Tester. As I look at Montana that's on fire right 
now, we've had--I don't know what the statistics are going to 
come back, but probably more 100 degree days in July than maybe 
we've ever had before, it's been incredibly hot there, it's 
incredibly smoky right now, the growing season has completely 
shifted from when I was a kid. The question for me becomes, 
what are the economic impacts if we don't develop this 
technology?
    Mr. Fehrman. We don't argue the fact that we have to do 
something, my point on this is that as we go forward with these 
types of technologies, we have to bring the regulators who 
regulate us along with us. They are bound by statute to select 
the least-cost alternative. Until that sort of policy has 
changed in one way or another, then you're placing the 
regulators who are assessing our willingness to do these types 
of things at risk. In fact, in our case, we have a public 
partnership, public/private partnership in place, with the 
Wyoming Infrastructure Authority, where we are looking to do a 
demonstration project with IGCC. We have talked with some of 
our regulators and the fact that the cost of that is so 
significantly higher than the next alternative that we have 
today, they're not clear that they would allow those costs to 
go through to our customers.
    Senator Tester. Gotcha. I gotcha. Point well taken, thank 
you.
    Thank you, Mr. Chairman.
    Thank you to the other members of the committee.
    The Chairman. Thank you, Senator Domenici.
    Senator Domenici. Mr. Alix, I think it's fair to say that 
you have an optimistic prediction for the deployment of 
technologies capable of capturing and sequestering carbon 
dioxide, especially in cases where this can be done at existing 
plants. Do you have a timetable in mind for the point at which 
your company will be able to guarantee these technologies?
    Mr. Alix. We've talked this over with our partners in 
building commercial designs, and estimates now, we believe that 
after the 100-megawatt-scale type unit, about 2012 is the 
timeframe we'll have that operating. We believe, in 2011, and 
within about a year of operation on a 100-megawatt-scale unit, 
we should be able to provide commercial guarantees there, 
consistent with all conventional pollution control equipment.
    Senator Domenici. Twenty eleven?
    Mr. Alix. Twenty eleven for the test, 2012 for the 
guarantees.
    Senator Domenici. OK. What is the response as you gather, 
of the companies to that kind of out-year assurance of 
guarantees?
    Mr. Alix. I think the initial reaction is quite a bit of 
skepticism, but once they get into the details of our process, 
and why we have confidence, and why we think the equipment's 
available to scale it, I think it becomes credible.
    Senator Domenici. Jim, let me ask you--I understand that 
Dow is a member of the United States Climate Action 
Partnership?
    Mr. Rosborough. That is correct, Senator.
    Senator Domenici. Which has called for mandatory limits on 
CO2 emissions in the United States. Current economic 
conditions have led to an increasing pattern of Dow and other 
manufacturers moving investment from the United States to 
China. In your opinion, would mandatory limits on carbon 
dioxide solely in the United States increase or decrease the 
trend in the world?
    Mr. Rosborough. Senator, thanks for the question.
    We look at it as an integrated problem, and therefore an 
integrated solution is necessary. We believe that action on 
emissions is necessary, and at the same time, incentives on new 
technology to stimulate alternative feed stock development in 
the United States, and its conversion to chemicals, and 
plastics, and fuels is the best way, overall, to go.
    We are a global company, and we have investments around the 
world that are made for a variety of reasons--both in low-cost 
Feedstocks, as well as where the high-growth markets are. China 
is clearly a market that we're going to invest in, in the 
future. Really, our interest here in the United States is let's 
revitalize our assets here, and let's reenergize the United 
States to become a growth market for the Dow Chemical Company, 
and other industry players again.
    Senator Domenici. One last question, and then I'll stick 
around.
    Will Dow incorporate carbon dioxide capture and storage 
when, and if, they construct coal-based chemical manufacturing 
facilities in China?
    Mr. Rosborough. Senator, another good question.
    We have a corporate goal to reduce absolute carbon dioxide 
emissions by a significant percentage over the next 15 years. I 
can't, right now, give you the exact number, but it's on the 
record, we've stated that on our website, www.dow.com, we list 
that.
    The project in China will adhere to the rigid environmental 
standards that we set globally, because as a company that wants 
to lead the way in environmental stewardship, we feel it's 
necessary to demonstrate environmental stewardship even in 
places like China.
    Senator Domenici. I'm not sure we can make you do that, 
obviously, that's overseas, but in a sense, you would cause a 
great deal of disbelief in your statements with regard to 
corporate activities if you went one way here, and another way 
in China in striking out at the same problem. That would put us 
in a very difficult position. Say, we were for climate change 
control, and we pushed it here, and you were working like 
beavers to get it done, and we had all of these things in our 
law that we changed, and we see your company over there in 
China, doing part of it, but not the tough part. The tough part 
you leave off, the easy one, you say, ``You don't have to do 
that,'' to your Chinese partners, ``You're good without it.''
    You understand that'd be pretty bad, right?
    Mr. Rosborough. Senator, I understand your point. The Dow 
Chemical Company has a global strategy, we believe that climate 
change is a global problem which requires a global solution.
    Senator Domenici. Thank you very much.
    That's enough for me, Mr. Chairman. Thank you.
    The Chairman. All right.
    Senator Corker.

          STATEMENT OF HON. BOB CORKER, U.S. SENATOR 
                         FROM TENNESSEE

    Senator Corker. Well, thank you, Mr. Chairman, and I 
appreciate you having this hearing. I think the testimony that 
all of you all have given has been excellent.
    You know, this September, I guess, we're going to be 
debating--I think, there's a possibility we're going to be 
debating carbon cap and trade programs, and I guess, to me, 
there's an opportunity for us to marry, if you will, the issue 
of energy security with the issue of climate change, if we do 
it the right way. I know that some of you have pointed out 
solutions. Also, I guess, there are issues of logistics and 
that is getting the gas piped to the right places, getting the 
carbon piped, or shipped, to the right places.
    But I wonder if you had any comments about if something's 
enacted, it might be in the very near future, and my biggest 
concern about it is, what do we do with coal? That's the one 
area that seems to me to be hanging out there, if you will, and 
very difficult for us to deal with in the short term. I know 
I've only got a few minutes here, but I'd love to have a short 
perspective on the kinds of things--forget the incentives that 
you've talked about, but some of the things we ought to 
contemplate, if you will, in any kind of carbon cap and trade 
bill that might pass the Senate, as it relates to coal and 
timing.
    I'll let all of you say that, although I want to make sure 
I have the opportunity to ask two more questions, so be brief.
    Mr. Fehrman. Very quickly, my only response in this would 
be to ask that the level of implementation of a program 
generally matches the availability of the technology to meet 
it.
    Senator Corker. I guess, you know, of course, we had the 
Energy Department in several hearings ago, and they talked 
about commercial viability of sequestration at 2045, you all 
have obviously given a much shorter horizon on that, in some 
cases, but I think we have to look at it on a broad basis for 
it to make a difference, and I'm just a little concerned about 
how we match those two together, and again, any editorial 
comments, I'd love to have over the next 30 seconds.
    Yes, sir, Jim.
    Mr. Rosborough. Senator, in Dow's view, coal has to be in 
the mix for Feedstocks. It is known to have a CO2 
footprint issue associated with it, but we believe there is 
also technology existing already that can advance that problem 
to a solution. I think enhanced oil recovery has been mentioned 
many times today. That's a good solution because it takes the 
CO2 and uses it for an economic benefit. Whenever 
that's possible, we should do that.
    Senator Corker. But that's, again, regional, I think. We 
have the same issues, in many ways, with carbon sequestration 
that we have with ethanol, and that is, it's produced 
regionally, but hard to get--I think because of the time, what 
I might do is ask that you all be available for some questions, 
because I think we have an opportunity, actually, to get it 
right, in many regards, if we think about it thoroughly.
    Let me just ask Jim one other question, I was interested in 
the ranking member's questions--would Dow be interested in a 
carbon cap and trade program, even if all of the allowances and 
credits were optioned on the front end?
    Mr. Rosborough. I think we'd be interested in looking at 
it, because we're interested in creative solutions to a very 
complex problem. I couldn't commit that we'd be interested in 
it and want to see it implemented without knowing more details 
about how it would work, and economic impact on the 
corporation. But, we're very open-minded to creative solutions.
    Senator Corker. No, just give me a judgment--a lot of the 
very sophisticated companies--and I would consider Dow to be 
one of those--certainly are crowding around all of us on cap 
and trade, because the sophisticated companies might get free 
allowances on the front-end, which is obviously very 
beneficial. The less-sophisticated companies, obviously will be 
out in the hinder lands, not doing so--how much of that is 
weighing in to some of the major companies coming here, and 
supporting--if you will--a cap and trade program, in your 
estimation, as an individual, not as an employee of Dow?
    Mr. Rosborough. It's hard for me to separate the two, but 
I'll say this--any project we look at, from now on into the 
future, contains with it a cost estimate dealing with the 
carbon footprint. So, we are planning that, from now on, any 
plant that we produce, or any plant that we build, will have a 
carbon solution that goes along with it.
    Senator Corker. Let me just ask one last question--I still 
have 14 seconds--thank you, Mr. Chairman.
    I really am interested in this, I think we have a 
tremendous opportunity to work together toward a good end. Some 
of you have talked about the initial base cost of carbon 
sequestration and some of you have talked about it on a per-ton 
basis. Our Chairman, here, has a bill that actually has a, sort 
of a, safety valve price of carbon per ton, and I'd be curious 
for all five of you just to give me an estimate, as to what the 
price of carbon has to be, per ton, adding in the initial fixed 
cost the capital base you have to put in on the front-end--what 
does the price per ton have to be to make sequestration--let's 
say in the year 2018--viable to be competitive with some of the 
other Feedstocks and supplies? Just, give me a number.
    Mr. Langley. Thirty-five dollars a ton.
    Mr. Perlman. I think closer to $20 a ton.
    I just want to briefly comment on one thing.
    Senator Corker. OK.
    Mr. Perlman. I definitely think you should implement the 
programs, because we've got an amazingly innovative country 
that's going to come up with technologies and solutions, and 
there's a venture capital community here that's going to fund 
them. So, if you implement a program, and you give people 
visibility, and it's the opportunity that technology will be 
there.
    Senator Corker. I really am very interested, I just want to 
make sure that we do things right, and I appreciate you saying 
that. I agree, we have an opportunity, innovatively, to do some 
things here in our country that could make us a leader, but 
we've got to do it the right way.
    Yes, sir.
    Mr. Alix. I'm in that $20 a ton ballpark.
    Senator Corker. Jim.
    Mr. Rosborough. I suppose my colleagues have bracketed it 
for me, and I have to say I don't really know the answer. We've 
studied it a bit, but we've looked at other studies, and 
they're sort of doing an average of the averages right now. It 
requires some specific due diligence on our part before I can 
answer your question, Senator.
    Mr. Fehrman. I agree with Jim.
    Senator Corker. So, the last two guys ought to run for the 
Senate.
    [Laughter.]
    Senator Corker. I would--thank you all--I'm just kidding--
thank you all very much for your testimony, and I hope that 
we'll be able to talk, talk to you all more in the future. 
Thank you very much, I appreciate it.
    The Chairman. Thank you all very much.
    Let me ask a question here--one of the issues that I can't 
quite understand, we're informed by developers of these new 
power plants that they cannot commit to deploying this new 
technology, unless they've got a performance guarantee from the 
vendor of the technology, or at least that's sort of what I've 
heard from some of them.
    It seems as though, I guess, Mr. Langley, let me ask you--
you mentioned that your company's involved in developing a 300-
megawatt oxy-coal combustion plant with CO2 capture. 
Does that mean that you have been able to issue a guarantee on 
this technology on that size plant? Was that not required or 
what?
    Mr. Langley. The plant had a--I'll say, a fairly unique 
structure. We did issue some guarantees, but they were limited 
in nature, so the risk of that project has been shared jointly 
between the providers and SaskPower Corporation.
    The Chairman. I guess this question of where the risk gets 
placed is key in all of this--how much of it is with the 
technology developer, how much of it is with the plant that's 
being constructed, I mean, the owner of the plant, how much of 
it is with the Government.
    Mr. Rosborough, you folks, in working, in supporting 
Senator Tester's bill--and I think, in your testimony today as 
well--call for a Government guarantee of 50 percent of the cost 
of the various gasification plants that you believe could be 
built. Why is a loan program superior to a guarantee of a loan?
    Mr. Rosborough. Thank you, Senator. The issue for us is, 
we're thinking about mega-billion dollar chemical complexes, 
because that's sort of the way we do our business, we feel 
economies of scale are necessary to compete globally. So, you 
talk about an integrated site of, to $6 or $8 billion of a 
gasification-based technology, and compare that against a $2 or 
$3 billion conventional alternative investment. We look around 
at the investment banks available, and the kind of moneys 
necessary, from one single entity to make the kind of a loan, 
is actually getting problematic, and we think it's possible 
that you might develop a consortium of lenders that could do 
it. So, we're open minded to that. But we just think it's more 
feasible to consider a direct-loan program with the Government, 
where the money comes from the most secure entity that I can 
think of.
    The Chairman. You also talked about a consortium of 
industrial companies that would work in partnership with the 
Government to, essentially proliferate these gasification 
projects. Is that consortium pretty much in existence at this 
time? Or is that something that would have to be created, down 
the road--where are we with that?
    Mr. Rosborough. It is not in existence today, Senator, but 
it can be created down the road. I would say, given the 
priority that we're all putting on this subject, we'd be able 
to create that fairly readily.
    The Chairman. Because I think about some other areas that 
are not particularly analogous, but I remember when the 
semiconductor industry came together, and essentially developed 
a proposal, and came to us--here in Congress, came to the 
Administration first, and said, ``We need to establish a Semi-
tack,'' and the Government put up half the money, and the 
industry will put up half the money and that will allow us to 
remain in the lead in the world in developing these new 
technology for semi-conductors.
    So, you're talking about something similar in this area, as 
I understand it, where industry would come together and agree 
to fund half of the cost of a major new industrial effort. Is 
that a correct interpretation of what you're saying?
    Mr. Rosborough. I think so, Senator, I think that's a fair 
assessment of a program that we've got in mind.
    The Chairman. Can you do that--you know, a lot of what Dow 
Chemical does has nothing to do with coal-to-liquids.
    Mr. Rosborough. That's correct, Senator.
    The Chairman. You know, coal-to-liquids has become a bit of 
a difficult issue here in the Congress, and in our National 
debate, because of concerns about emissions.
    It strikes me, though, that what you're proposing, the main 
thrust of what you're proposing does not get us into coal-to-
liquids. It is talking about industrial gasification projects 
to produce all sorts of useful products that clearly we're 
going to need going forward. Am I correctly interpreting that?
    Mr. Rosborough. Senator, that's correct. We think, I mean, 
our industry has been tied to fuels producers ever since it 
began. The by-products of fuels manufacturers are the 
Feedstocks for our company. A coal-to-liquids regime would, in 
fact, produce Feedstocks for Dow, but we don't think stopping 
at liquids is the most efficient way to go about it, we think 
that carbon maximization, carbon efficiency maximization 
requires you to take electricity, fuels, chemicals and 
plastics, and do them all together in one spot.
    The Chairman. OK.
    Mr. Rosborough. So we advocate a polygeneration kind of 
approach.
    The Chairman. Senator Domenici.
    Senator Domenici. Yes, thank you.
    Senator Bingaman, let me say, this is a very good 
opportunity for our committee to take a look and see if we're 
really interested in doing something, or if we want to do some 
more talking. But, I'm not so sure that what we're presenting 
for our members to take, is well, before I finish that 
sentence, let me ask--would Dow be, at the offset, the most 
logical and perhaps most appropriate in the marketplace to do 
this? Or are we saying there would be more than them that could 
do it. It's just that they and others would have to get with it 
to propose this kind of efficiency.
    Mr. Rosborough. Senator, thanks for the question. The Dow 
Chemical Company has been integrated in the manufacture of 
chemical, plastics and electricity ever since our inception, so 
we have already been a practitioner of polygeneration.
    Senator Domenici. Right.
    Mr. Rosborough. In that regard, it puts us as a logical 
member of a consortium.
    Senator Domenici. Yes.
    Mr. Rosborough. We're happy to take a leadership role in 
something, because we also know how to operate, build and 
manage mega-projects. But, we're not coal experts, we're not 
carbon sequestration experts. We're not exactly on the cusp of 
some this new technology, as my friend, Mr. Perlman, for 
example, is.
    So, we believe a consortium of multiple, of multiple 
entities is important, and how it actually ends up getting led 
and managed, would be up to the members of the consortium, I 
think.
    Senator Domenici. I don't think, in the end, that it's 
going to be quite like the entity that was put together, that 
both you and I were involved in, with others, where we had a 
Secretary of Defense who many thought was a stubborn old ox, 
and it turns out, you all know who he was. He turned out to be, 
on these kinds of things, more right than wrong. He joined in 
making sure that the Department of Defense was heavily involved 
in this mix and match, so that America would take the lead in 
the world. Just takes us a couple of years to get there, and a 
lot of resources.
    Whatever the model that we would look at and say, this is 
what it is, it's fine with me. I think we have to start talking 
about how do we get there. You all have been doing some talking 
about how you get there, from what I see. That's good. We're 
not operating in a vacuum. I believe something like this must 
be done. It's a terrible vacuum, and it's going to be filled. 
We better get with it, or we won't fill it.
    You all are saying, to this group--not only is that true, 
Senator, but we're telling you that we know somebody will fill 
that, because it's too natural to not happen, right? It's going 
to happen. It's not a hard thing, it takes a lot of hard cash, 
you know--there's a lot of that around, too, just given the 
right project, right? It doesn't matter whether it's $6 billion 
or twenty--they're going to get the money, they're going to 
have the money, if you give them the right proposal, they'll 
find the money.
    So I want to say, Senator, I think we came together, maybe 
it was for a different reason, a little different. But I want 
to put my two cents up there that I don't know why we're going 
so slow on some of these. You've admitted here for awhile that 
if you choose the wrong vehicle, you start off with a negative 
receptivity. We don't want that. We want to make sure that 
people like you and I can both be for this, right? Not that we 
fight, and saying we're not bored, we've got to say that you 
and I and therefore, a rather large group of these people here, 
feel like this is really doing something for the country. It is 
doing something for the country. Because if we don't do this, 
and we let you all get away and don't do it, we're making a big 
mistake. If you all think you can you know, play games with us, 
and not be competitive, but just say, ``We know we've got 
America here, they've got to have us, and so we're going to 
take them,'' well, that ain't gonna happen either. Because I 
think we do have enough smart people that it won't happen.
    Mr. Chairman, thank you, it's a good meeting and I learned 
a lot and I appreciate it.
    The Chairman. Thank you very much.
    Senator Barrasso.
    Senator Barrasso. Thank you, Mr. Chairman, I know the hour 
is late and others need to be places, but I want to follow up 
on a question you asked, Mr. Chairman, and I want to agree with 
my distinguished ranking member of this committee, Senator 
Domenici, and his comments.
    You know, we have 250 years of future for coal, there's so 
much in the United States, and Australia, and China, it's going 
to be used, and we need to develop the technology, and as 
rapidly as we can, to make sure that those energy resources are 
there, and we're less dependent on international and Middle 
East sources of energy.
    My question for Mr. Fehrman, and I appreciate what you do 
in Wyoming, and it's not just coal, I think I read a recent 
story about some wind generation and renewables and a 
commitment of your company to all of those things. But, I'm 
especially impressed in your comments and in your testimony, 
talking about how PacifiCorp was chosen as the Wyoming 
Infrastructure Authority's partner to pursue the high altitude 
IGCC plant in the State, and designed to use the Powder River 
Basin Coal. You said you needed some of the Government's 
support on that.
    When the Energy Bill was passed--although I wasn't a member 
of this body, it said to me, the Government should be a player, 
a partner, and I don't think that the Government has come along 
to that degree.
    I read some of your comments about some of the things you 
need accelerated--depreciation, investment and production tax 
credits--do you have a timeline on some of those things? How 
much you need, for how long of a period of time? To make this 
specific program in Wyoming possible and doable, and get 
started?
    Mr. Fehrman. Thank you for the question.
    The key driver on the issue with the Wyoming Infrastructure 
partnership that we have is really tied to the section 413 
dollars that are in the Energy Policy Act, and both the WIA and 
ourselves are looking for Government support to go through the 
funding mechanism to basically bring down the cost of this 
project, such that when we go to our regulators, the cost of 
the IGCC project will be neutral, or least cost, as compared to 
other alternatives, as to my earlier comment on the process we 
have to follow.
    So, we have laid out with the WIA the funding program, and 
essentially, the sooner we can get funds to support the 
project, the sooner we can begin. This is a case where we will 
not be able to invest significant development dollars into this 
program, until we have some sort of assurances that there will 
be the section 413 dollars coming through to help offset that 
difference in cost between various types of technologies.
    Senator Barrasso. Thank you, Mr. Chairman. I know the hour 
is late and you have other things to go to. I appreciate it.
    The Chairman. Thank you very much. I think this has been 
very useful testimony and we appreciate you all being here and 
giving us the benefit of your views. We may have some follow up 
questions, and if we do, we'll be in touch. Thank you, again, 
for your patience in getting us through this delay we had to 
put you through.
    Thank you.
    [Whereupon, at 12:28 p.m., the hearing was adjourned.]
                                APPENDIX

                   Responses to Additional Questions

                              ----------                              

       Responses of Frank Alix to Questions From Senator Bingaman
    Question 1a. We have been told by several witnesses in the past 
that, absent a price on CO2, there is no business case for 
capturing. What's different about your pilot project at the Burger 
Plant?
    Answer. Powerspan has venture capital investors who believe that a 
cost effective system to capture CO2 from existing coal-
fired plants may be highly valued in the future. They are motivated to 
invest in our pilot project based on expectations of a return on their 
investment.
    Question 1b. What's FirstEnergy's incentive to take on the 
additional costs?
    Answer. FirstEnergy is an investor in Powerspan and also has 
several coal-fired plants that would benefit from a cost-effective 
CO2 capture solution, should power generators face 
CO2 emission limits in the future.
    Question 2. Your technology is particularly attractive since it may 
be adaptable to the existing fleet. How extensive do you imagine such a 
retrofit would be at a typical PC plant?
    Answer. The retrofit for our ECO2 system would be 
similar in scope to a wet scrubber retrofit installed for 
SO2 reductions.
    Question 2b. Do most plants have sufficient space and a 
configuration that would accommodate retrofit?
    Answer. Most plants would have sufficient space and a configuration 
to accommodate a CO2 capture retrofit, however the degree of 
difficulty and associated cost of plant retrofits would likely show a 
large variation.
        Responses of Frank Alix to Questions From Senator Corker
    Question 3a. As the Senate prepares to debate cap-and-trade 
legislation this fall, please give me your perspective on how we should 
contemplate and deal with coal in the short-term during that debate, 
apart from the incentives that you laid out in your testimony.
    Answer.Powerspan recognizes the need to provide for certainty 
regarding CO2 emission reductions, but also the wisdom of a 
cap and trade approach, which incentivizes the lowest cost solutions.
    Question 3b. Keeping in mind the need to rely on coal as part of 
our future energy mix, what do you think are appropriate emissions 
targets in what amount of time, such that we challenge industry without 
being unrealistic based on what is technologically possible?
    Answer. Powerspan does not have a specific position on 
CO2 emission targets or timing since once technology is 
available, such a decision is largely an economic tradeoff of cost 
against perceived climate change risk. Meaningful CO2 
emission reductions from coal plants in the short term--i.e. 5-10 
years-are probably not viable because required CO2 capture 
and sequestration (CCS) technology is still in the development and 
demonstration phase. However, the technology should be available to 
make reductions by the 2015 time frame. Once CCS technology is 
available, history has shown that the power industry can retrofit 
approximately 10% of the operating fleet annually without undue burden 
on electricity supplies.
                                 ______
                                 
     Responses of Andrew Perlman to Questions From Senator Bingaman
    Question 1. You mentioned that your process does not produce the 
slag that conventional gasification plant does. What is the solid-waste 
product of your process?
    Answer. The unreacted carbon and mineral matter in the coal removed 
from the gasifier is treated very thoroughly to recover our catalyst 
leaving a clean, highly porous, and environmentally benign solid 
material we believe will have valuable byproduct credit.
    Question 2. How do you control conventional pollutants such as 
sulfur dioxide and mercury that are generally produced from 
constituents in coal?
    Answer. The gasification process does not produce sulfur dioxide 
but rather hydrogen sulfide which is easily removed from our product 
gas stream and converted to saleable elemental sulfur. Any volatilized 
mercury is captured in an activated carbon bed and can be safely 
disposed.
    Question 3. You envision capturing the CO2 from the 
process of deriving your natural gas equivalent; do you have any 
similar plans to capture CO2 from combustion of the gas for 
power generation?
    Answer. Great Point's process produces synthetic natural gas, which 
has the same basic chemical composition as natural gas, or methane--
CH4. Because coal contains a higher ratio of carbon to 
hydrogen than natural gas, the carbon that Great Point will capture in 
its process is the excess carbon, above and beyond that contained in 
the CH4, that would otherwise be released to the atmosphere 
as carbon dioxide if coal were burned in a conventional coal-fired 
power plant instead of being gasified.
    Great Point's process, which produces CH4 and allows 
capture of the excess CO2 from coal, does not in itself 
involve combustion of CH4 for power generation, nor would 
Great Point own or operate gas-fired power plants. Great Point is a 
fuel supplier.
    The CO2 that is produced when CH4 is burned 
(by others) for power generation is not currently captured by any 
commercial technology, although post-combustion capture technology is 
actively being worked on by many (other) companies. However, because 
burning CH4 for power generation produces so much less 
CO2 than burning coal for power generation, a power plant 
that emits no more CO2 per megawatt hour than a combined 
cycle natural gas-fired power plant is considered to have a good carbon 
footprint, not a bad one. The CO2 emissions per MWh of such 
a plant currently represent the standard (or limit) for purposes of the 
new Emissions Performance Standards (``EPS'') recently adopted as a 
progressive, climate-friendly measure by California, Washington, and 
other states. By making more fuel available for this comparatively 
climate-friendly method of power generation, Great Point will be 
contributing to lower power sector CO2 emissions overall.
     Responses of Andrew Perlman to Questions From Senator Sanders
    In your written testimony, you are very enthusiastic about the 
prospects for your company's technology, which will convert coal to 
cleaner natural gas utilizing catalysts instead of conventional coal 
gasification technologies, which are much more complex. You mentioned 
that you have significant financial backing and suggest that your first 
major project will be online by 2011 or 2012. You testified that your 
company would be in a position to give vendor guarantees by 2012, so 
that the technology could be readily purchased on the commercial 
market. This sounds very promising especially as other witnesses did 
not project this kind of progress with their ideas until 2020.
    Question 4a. Why then, do you suggest that it would be useful to 
your company to be eligible for a 50 cent per gasoline gallon 
equivalent production tax credit for the generation of this natural 
gas?
    Answer. We are just as enthusiastic about our prospects for 
commercial success as your question suggests. The value and importance 
of the proposed production tax credit for the energy output of our 
technology, while still in its early stages--and the logic supporting 
such a credit--are precisely equivalent to those that support credits 
for other relatively new (although by now significantly older) climate-
friendly energy technologies, such as wind energy and biofuels 
production. In summary, new technologies, even when first deployed at 
commercial scale, typically debut with somewhat higher costs and less 
perfect performance than they will attain once they have greater 
operating and design experience, can be optimized and ``tuned,'' and 
can enter into larger-scale production of greater numbers of units and 
thereby reduce average costs.
    There are also substantial ``pioneer's penalty'' risks for 
investors, lenders, and early adopters, as well as the company itself, 
during the period when the technology is still relatively new at 
commercial scale and relevant infrastructure is not yet fully 
developed.
    A production tax credit is a tried-and-true method of stimulating 
early adoption of climate-friendly new energy technologies in the face 
of such initial hurdles.
    Question 4b. Do your financial projections suggest that you will 
not be able to make a profit without this credit?
    Answer. No, but the primary concern at this stage is necessarily 
how best (and most quickly) to attract equity investment and necessary 
debt from private capital markets, in order to speed the construction 
of production facilities. For the reasons set forth immediately above, 
and as demonstrated by the experience of wind energy, the production 
tax credit makes it far easier to attract both equity investment and 
lenders for large-scale commercial deployment of new energy 
technologies in their early years. There are more risks and initially 
higher costs associated with new technologies in their earlier stages 
than will be the case in later years, and the PTC is one method of 
reducing such risks and helping ``level the playing field'' for 
desirable new technologies in the stage when they naturally involve 
initially higher costs than established alternatives.
    Question 4c. At what price do you expect to be able to sell your 
natural gas in 2011-12? What do you project the cost of conventional 
natural gas to be at that point?
    Answer. Great Point expects to sell its gas at market prices from 
the outset, although not necessarily in the spot market or at spot 
market prices (the prices most frequently quoted in industry and news 
reports). Much of our gas may instead be sold under long-term 
contracts, in which the buyer gets the benefit of Great Point's coal-
based production costs, relative price stability, and protection from 
the degree of price volatility that has characterized the market for 
natural gas in recent years. Some of Great Point's large industrial 
investors certainly hope to obtain these benefits from the technology, 
as well as any savings the technology may make possible vis-AE2a-vis 
natural gas prices.
    Great Point itself does not prepare projections of natural gas 
prices, and instead relies on projections from the same public sources 
available to the Committee.
    Question 5a.You also suggested that setting a price floor for 
natural gas produced from gasification of domestic feedstocks such as 
coal or biomass would also provide assurances that your product would 
be profitable, even if the price of conventional natural gas were to 
fall below this price floor. At what level do you think such a price 
floor should be set?
    Answer. Ideally, the price floor would be (i) temporary, not 
permanent, and (ii) high enough, but no higher than necessary, to 
assure the profitable operation of the initial commercial facilities 
that employ the synthetic natural gas production technologies the 
Committee decides to encourage. Speaking only for Great Point, not 
other technology developers, in today's dollars such a price floor 
might reasonably be set at $[X] per MMBtu of gas produced.
    Question 5b. Do you project that there will likely be conventional 
natural gas prices below your profitability floor anytime soon?
    Answer. No, not on any sustained or nationwide basis. But natural 
gas prices are highly volatile and often vary sharply by season, 
region, and in response to fluctuations in storage levels. There will 
certainly be ``valleys'' in natural gas prices in particular localities 
or circumstances where the existence of a price floor for synthetic 
natural gas would help assure that production of synthetic natural gas 
proceeds and continues despite such fluctuations.
    As you know, the history of new energy technologies is that both 
Federal and private sector efforts to develop such technologies have 
tended to surge when oil and natural gas prices are high, and halt when 
oil and natural gas prices drop--even though the drops have all proven 
to be temporary ``retreats'' on an ever-upward march. The country would 
be better off today if temporary drops in natural gas prices had not 
undermined development of new energy technologies in the past. If this 
cycle is to be broken, the new energy technologies should be supported 
consistently, and particularly in the face of inevitable temporary 
reductions in natural gas and crude oil prices.
    Question 5c. If so, what is your estimation of the total Federal 
cost of such a price stabilization provision?
    Answer. The appropriate total Federal cost (if any cost actually 
results) of such a price stabilization provision is a policy matter on 
which Great Point expresses no opinion. We would observe, however, that 
(a) there may be no federal cost at all, or very little, if as expected 
natural gas prices remain above the Congressionally-mandated price 
floor all or most of the time, and (b) Congress in any event can design 
the program to be something other than open-ended, or a blank check. 
For example, the program could have automatic phase-out or sunset 
provisions once synthetic natural gas production reaches a specified 
total annual volume, or a specified percentage of annual natural gas 
consumption. In any event, we would not expect the total federal cost 
of such a price stabilization provision even to approach the total 
federal cost of programs, past and present, to support the prices or 
reduce the costs of domestic oil and gas production.
    Question 6. For some time now, the price of natural gas has been 
very volatile. Would you expect the price floor you mentioned to be 
established in such a manner that when the price of natural gas was 
below the price floor, the government would provide funding to your 
company to reach the price floor, and conversely, when the market price 
was above the floor, that this funding would be paid back to the 
government? Or would it be more advisable to establish a long-term 
(multi-year) calculation of the market price to determine if it would 
be below or above the price floor?
    Answer. We would be happy to work with the Committee to help design 
a price floor program the Committee considers reasonable and feasible. 
Many variables are involved, and many possible approaches could work. 
For example, the price floor protections might be triggered only after 
natural gas prices had remained below synthetic natural gas production 
costs for a specified period of time. Or the protections might be made 
available to those who purchase the synthetic natural gas at contract 
prices, such as electric utilities, rather than to the producers of 
synthetic natural gas such as Great Point.
    If the price floor provisions of such a program actually resulted 
in money changing hands, and if Great Point itself, as a producer, 
actually received any of that money, then of course Great Point would 
expect that the program would be designed in such a manner that money 
might also be paid back to the government if sales prices for synthetic 
natural gas exceeded some specified level. That would be appropriate 
and fair.
    Again, Great Pont would welcome the opportunity to help the 
Committee design a program satisfactory to the Committee in all 
respects.
       Response of Andrew Perlman to Question From Senator Corker
    Question 7. As the Senate prepares to debate cap-and-trade 
legislation this fall, please give me your perspective on how we should 
contemplate and deal with coal in the short-term during that debate, 
apart from the incentives that you laid out in your testimony.
    Keeping in mind the need to rely on coal as part of our future 
energy mix, what do you think are appropriate emissions targets in what 
amount of time, such that we challenge industry without being 
unrealistic based on what is technologically possible?
    Answer. We believe that, in general, the so-called ``California'' 
emission performance standards (``EPS''), recently adopted in 
California and Washington, among other states, are appropriate for 
power generation facilities. Basically, these particular EPS establish 
emissions targets per megawatt hour of power production based on the 
CO2 emissions of efficiently-operated combined cycle 
natural-gas fired plants. Currently, this means about 1100 pounds of 
CO2 per MWh in both California and Washington, although the 
best natural gas-fired plants are capable of CO2 emissions 
of less than 900 pounds per MWh, and both California and Washington 
have made provision for the applicable standard to become tighter and 
lower as average natural gas fired power plant emissions are reduced.
    Natural gas-fired power plants can meet these standards by using 
synthetic natural gas from Great Point Energy and other producers.
    For coal gasification power projects to meet these standards, some 
form of carbon capture and storage (``CCS'') will be necessary. 
Enhanced oil recovery (``EOR'') can provide an appropriate transitional 
form of CCS in localities where EOR opportunities exist, provided 
reasonable oil field management practices for CO2 are 
followed. Both CCS and EOR are currently technologically possible. 
(Even geological sequestration of CO2 appears 
technologically possible, although currently rather costly.)
    For coal combustion power plants to meet these standards, post-
combustion capture technology as well as CCS would also be required. 
Great Point is not the best source of information for the Committee on 
when post-combustion capture is likely to be considered technologically 
possible.
                                 ______
                                 
       Response of Bill Fehrman to Question From Senator Bingaman
    Question 1. You mentioned that for resources planning purposes 
PacifiCorp estimates the cost of CO2 at eight dollars per 
ton. What led you to that number? Have the various bills introduced in 
Congress assigning prices to CO2 caused you to revise that 
estimate?
    Answer. Beginning in 2002, PacifiCorp looked at a variety of 
externally available data, including: (1) the current greenhouse gas 
offset market, including offset investments made by The Climate Trust 
established by Oregon law, (2) existing greenhouse gas markets in the 
United Kingdom and the European Union, and (3) U.S. macroeconomic 
analyses of scenarios involving limits on greenhouse gas emissions. At 
the time the analysis was done, the offset market yielded estimates at 
the low end of the range and helped the company define a low 
sensitivity of $2/ton of carbon dioxide. The existing overseas markets 
were operating in the range of $8/ton. Public comment on the value to 
use has been sought as part of each subsequent Integrated Resource Plan 
and ultimately resulted in the use of $8/ton for our models Regarding 
its current adequacy, the company now believes it to be on the low side 
based on legislative developments.
    Question 2. The MIT report, and others, have pegged $30 per ton as 
the price that would drive utilities to capture and sequester 
CO2. Do you generally agree with this estimate?
    Answer. Technology, costs and regulatory environment associated 
with CO2 capture and sequestration are as yet undefined. 
Therefore, it is hard to conclude exactly what would happen at $30 per 
ton.
    Question 3. We talked a bit about the order in which additional 
power is ``called up'' to meet demand, with the effect being that lower 
CO2-emitting natural gas generation is used less due to high 
natural gas costs. Do you have an opinion regarding the potential 
effects on energy prices and technology deployment if some regulatory 
mechanism were put in place to mandate increased use of lower-emitting 
generation?
    Answer. We can expect increased demand for gas-fired generators, 
increased focus on nuclear energy and deferrals/cancellations of coal-
fired plants until there is much more certainty over the costs of 
CO2 emissions compliance. I would expect higher gas and 
wholesale electricity prices as a result, in addition to increased 
volatility. Increased wind penetration will help dampen the upward gas 
and electricity price trends. Regional transmission projects will be 
relied upon to more efficiently utilize existing generating assets and 
support wind resource expansion.
    Some of the key drivers behind technology deployment in the future 
include: (1) the structure and scope of CO2 regulations, (2) 
the impact of CO2 regulations on load growth, (3) commercial 
success of CO2 removal technologies for conventional coal 
and IGCC, and (4) when the path to widespread CO2 
sequestration can be made from a regulatory and legal standpoint.
      Responses of Bill Fehrman to Questions From Senator Domenici
    Question 4. Mr. Rosborough describes gasification as 
``technologically proven'' in his testimony, and yet you assert the 
opposite. Your statement maintains that, ``IGCC is not a commercially 
viable technology at this time.'' Is that statement based on the fact 
that adding turbines to the back end of a gasification unit is 
significantly more complicated than the processes undertaken by Dow and 
other chemical manufacturers, or is it a result of significantly 
different levels of experience in your respective industries?
    Answer. We regard ``technologically proven'' and ``commercially 
viable'' as two different things. For a regulated utility to adopt new 
technologies on a broad basis, equipment needs to be economically 
reasonable, available to meet specific performance guarantees, and 
operable as a utility dispatched asset. Current cost estimates relating 
to this technology show it to be significantly more expensive when 
compared to other generation options. IGCC refers to the integration of 
the gassifiers with the power block to gain efficiencies in the 
electrical generation process. While this integration adds 
efficiencies, it also adds complexity and is unproven at a commercial 
level.
        Response of Bill Fehrman to Question From Senator Corker
    Question 5. As the Senate prepares to debate cap-and-trade 
legislation this fall, please give me your perspective on how we should 
contemplate and deal with coal in the short-term during that debate, 
apart from the incentives that you laid out in your testimony.
    Keeping in mind the need to rely on coal as part of our future 
energy mix, what do you think are appropriate emissions targets in what 
amount of time, such that we challenge industry without being 
unrealistic based on what is technologically possible?
    Answer. On March 20, 2007, MidAmerican Energy Holdings Company 
chairman and chief executive Officer David Sokol testified before the 
House Energy and Commerce Subcommittee on Energy and Air Quality, at 
which he outlined the company's position on global climate change. Mr. 
Sokol told the Subcommittee the nation needs a phased-in technology and 
policy-driven approach to provide tools necessary to successfully 
reduce long-term global greenhouse gas emissions while minimizing the 
costs and risks to the economy and the impact on customers.
    In the short-term, or what Mr. Sokol referred to as the first of 
three phases (2007-2019), the company believes climate policy should 
focus on technology development and market transformation activities. 
In the electricity sector, MidAmerican proposed the following measures:

          1. Adoption of a flexible renewable energy portfolio 
        standard.
          2. More stringent energy-efficiency mandates.
          3. Policies to encourage efficiency improvements at existing 
        facilities.
          4. A 10-year, multi-billion dollar public-private research 
        and development program for emissions reduction.
          5. Removal of the legal and regulatory barriers to the 
        deployment of new technologies such as carbon sequestration and 
        new nuclear development.
          6. Tax policies to support these programs, such as a long-
        term extension of the renewable energy tax credit.

    In the second phase (2020-2029), as technologies become widely 
available, a hybrid system of phased-in emissions reductions based on 
carbon intensity targets, together with a carbon price cap (i.e., a 
safety valve), should be developed. The third phase (2030+) prescribes 
a hard emissions cap of 25 percent reduction of U.S. greenhouse gas 
emissions from 2000 levels by 2030, with additional emissions of 10 
percent in each succeeding five-year period through 2050.

    Mr. Sokol concluded his testimony with five points he said 
lawmakers should thoughtfully address in any global climate change 
legislation.
          1. The electric industry cannot change past decisions and 
        should not be penalized for past fuel choices.
          2. The feasibility and cost of clean energy technologies must 
        be known before they are deployed, because utility companies 
        and regulators have a responsibility to keep customers' rates 
        as low as possible.
          3. A recommitment to funding research and development in the 
        energy sector must occur.
          4. Failure to take technology development timelines into 
        account could result in unintended consequences, such as fuel 
        shifting from coal to natural gas, which already faces tight 
        supply-demand constraints.
          5. A cap and trade concept in itself will not reduce 
        emissions, bring new technologies on-line or reduce prices for 
        renewable resources. This complex issue cannot be solved that 
        simply.
                                 ______
                                 
Responses of Jerry Hollinden on Behalf of The National Coal Council to 
                    Questions From Senator Bingaman
    Question 1. The National Coal Council report advocates for 
significantly increased funding for R&D and demonstration projects. Do 
you envision that this will be primarily a federal government 
undertaking or an effort more akin to FutureGen or some other model?
    Answer. In all of its reports to the Secretary of Energy, The 
National Coal Council has consistently advocated the need for public/
private partnerships on major R&D and demonstration projects. This goes 
all the way back to the initial Clean Coal Technology program of the 
late 1980s. The combination of public support in the form of both money 
and policy, with that of private industry in terms of money, siting of 
project facilities and technology development have yielded dramatic 
acceleration in bringing the various technologies to the market place. 
The Council continues to support these types of collaborations.
    The Council has also consistently supported FutureGen since its 
inception, and the current report continues that support. Other 
examples of public/private partnerships supported in the Council's 
report include the Carbon Sequestration Regional Partnerships, the 
Carbon Sequestration Leadership Forum, the Asia-Pacific Partnership 
Program and the Clean Coal Power Initiative. While each of these 
efforts has a different combination of public and private input, they, 
along with many other similar efforts, all are examples of this kind of 
partnership. The Council does not favor one over any other and in fact 
supports them all.
    In summary, the Council believes that the best way to expedite 
getting technologies from the R&D phase to the market place is through 
a joint commitment by both public and private leadership.
    Question 2. Your Report echoes the MIT report in recommending 
undertaking on the order of 5 large scale sequestration projects. Given 
the significant amounts of CO2 required for a demonstration 
on this scale, where would such a project likely get the 
CO2? Is it reasonably likely anyone would be capturing 
CO2 at the scale necessary absent some new kind of specific 
incentive to do so?
    Answer. While The National Coal Council does have a member who is 
an emeritus professor from MIT, the full Council arrived at its 
recommendations independent of any of the MIT work. The recommendation 
for 5 major projects was a best estimate by the Council. It may be 
necessary to conduct more projects than 5, depending on the types of 
capture, transportation and storage technologies developed as the R&D 
effort progresses. The estimate was not meant to be a goal, but was 
meant to recommend that the necessary number of projects be completed 
in an effort to bring the largest menu of options to the market place 
so that carbon capture and storage could be achieved at the lowest 
possible cost and also to reduce risk, which may be even more 
important.
    As for the availability of sites for these projects absent a new 
kind of specific incentive to capture and store carbon emissions, the 
charge received by the Council from the Secretary of Energy was to 
``conduct a study of technologies to avoid, or capture and store, 
carbon dioxide emissions--especially those from coal based electric 
utilities.'' The Secretary did not ask the Council to investigate any 
incentives, new or old, for capturing CO2, and therefore, 
the Council did not make this a part of the study. However, in the very 
first paragraph of the Recommendations Section of the Executive Summary 
of the report the Council did acknowledge that ``the U.S. Congress will 
address carbon management in the near future.'' With the combination of 
the Secretary's request, the Council's strong recommendation to move 
forward in development of these technologies and the belief that 
Congress will act in the near future, the Council believes that site 
selection for these projects should be very manageable.
Responses of Jerry Hollinden on Behalf of The National Coal Council to 
                    Questions From Senator Domenici
    Question 3. Climate change is a global problem. I fear that a 
number of proposals to address this issue will merely result in fuel-
switching, or some other undesirable path forward. It is clear that 
other countries, particularly developing countries, will continue to 
consume coal in increasing amounts.
    In the absence of a binding international agreement, what clean 
coal technologies are developing countries likely to find desirable? 
Will developing countries have a preference towards efficiency 
improvements, oxygen-fired combustion, gasification technologies, or 
some other category that we can assist in the commercialization of?
    Answer. The Council report spent a considerable effort discussing 
the international energy market place. New and major players in this 
market place include China, India and some of the countries in 
Southeast Asia. The demand for energy will continue to increase 
dramatically as these countries continue to grow and develop. Each will 
develop their own energy resources and most of them have large coal 
deposits.
    Just looking at China as an example, they plan to increase their 
coal production from 1.7 to 3.2 billion tons per year by 2020. They 
intend to build 50 facilities to produce syngas from millions of tons 
of coal each year to fuel their industrial and agricultural sectors. 
They are planning to spend $20 billion on coal-to-liquids facilities in 
the next 7 years, and they are planning to build over 100 GWs of new 
coal-based electricity generation during that time as well. Other 
developing countries may not grow as dramatically, but they will grow 
and they will need clean coal technologies if they are to develop their 
coal resources.
    Each country will select the technologies that best fit their 
needs. Therefore, development of a wide array of technologies will best 
allow the U.S. to participate in this technology market place. Because 
of this, the Council has always supported a wide variety of R&D 
projects including more efficient electricity generation technologies 
as well as emissions control technologies. Oxy-firing, gasification and 
liquefaction as well as carbon capture and storage technologies should 
all be expedited for use both here at home and in the energy market 
place abroad.
    Question 4. I am concerned about the availability of technology, 
regulatory shortcomings, infrastructure sufficiency, and liability as 
it relates to carbon dioxide capture and storage. Do you believe we 
should deal with those issues before mandating carbon dioxide capture 
and storage, or including it as eligibility criteria for federally 
supported R&D projects? How do you suggest we best address those 
issues?
    Answer. The Council's report speaks to all of these issues. The 
technologies to capture carbon dioxide, while still in their infancy 
for the size and scale needed at generation plants, are the most 
advanced. Progress is being made because this has been the initial area 
of focus for R&D. However, the industry is still many years away from 
having proven capture technologies that could be applied commercially.
    There is currently no transportation infrastructure for moving 
carbon dioxide from the point of capture to the potential point of 
storage. This may require a whole new industry to be developed in order 
to be achieved. Transportation technologies are way behind the capture 
technologies.
    Storage of CO2 is being achieved on a small scale in 
regions of the country where it can be used for enhanced oil recovery. 
Because of this effort, storage issues are better understood. However, 
the scale at which these technologies will be needed for the volumes at 
which CO2 will need to be stored is incompletely understood 
at this time. All of the candidate geological configurations must be 
tested, as well as have the necessary monitoring data developed to 
ensure no leakage occurs.
    Finally, on the question of liability the Council has recommended 
that the Secretary work to determine the legal liabilities associated 
with carbon capture and storage. This includes resolving ownership 
issues and responsibility for stored CO2 in the event of 
leakage, and the implementation of long-term monitoring at storage 
facilities.
    The Council was not asked to address the issue of eligibility 
criteria for federally supported R&D projects, but it is clear that 
there is a need to develop technologies to address each of these 
issues.
    Question 5. It seems to me that efficiency improvements allowing 
generators to get more electricity out of the same amount of coal would 
be in their financial interest to pursue. Can you explain the 
disconnect that exists in this regard, and why plants have not 
maximized efficiency throughout the fleet? Is it because the savings 
associated with an efficiency upgrade do not justify the costs of the 
undertaking? Are there regulatory hurdles to pursuing these tasks? If 
so, please identify them for us.
    Answer. In May of 2001 the Council produced a report at the request 
of then-Secretary of Energy Bill Richardson (subsequently submitted to 
his successor, Secretary Spencer Abraham), that identified technologies 
that at the time could increase the amount of electricity from the 
existing fleet of coal plants by 40,000 MW. The approach set forth in 
those recommendations is still viable today, although several of those 
options may have been implemented already.
    These efficiency gains can be made at various points within the 
plants. They include steam turbine blade upgrades, improvements in 
condenser systems, and in the milling systems to grind the coal. In 
addition, the use of coal cleaned to higher quality levels can increase 
plant efficiency. The full suite of recommendations can be found in the 
study, ``Increasing Electricity Availability from Coal-Fired Generation 
in the Near-Term'' available on the Council web page at 
www.nationalcoalcouncil.org.
    Plant efficiency upgrades are a practical, quick and less expensive 
way to reduce CO2 emissions in the near term as well. Given 
current clean air regulations, however, many power plant owners would 
not initiate helpful upgrades because of concerns that such 
improvements would trigger requirements for more expensive upgrades 
under the New Source Review program. Dialog between DOE and EPA on how 
best to achieve progress on this issue was recommended. Streamlining 
the NSR program would be highly beneficial to achieving these 
efficiency gains as well as avoiding CO2 emissions.
                                 ______
                                 
       Responses of Carl Bauer to Questions From Senator Bingaman
    Question 1. The FutureGen government-industry partnership will 
demonstrate a number of important technologies but, as you mentioned in 
your testimony, there are a number of other technologies that will need 
similar demonstrations at commercial scale. Presuming they can't all be 
demonstrated through similar partnerships, can you give us some 
examples of alternative pathways to commercialization of advanced 
technologies?
    Answer. In addition to the Department of Energy's (DOE's) FutureGen 
partnership, the most logical route to the commercial-scale technical 
and economic validation of developing technologies is through DOE's 
Clean Coal Power Initiative (CCPI). The CCPI program is unique to DOE 
in that it requires a minimum 50% participant cost-share, and a 
Repayment Plan based upon the public's sharing in any profits derived 
from commercialization of the technology demonstrated, with the 
objective of full-cost recovery of the entire amount of our project 
investment.
    Question 2. Can you give us a sense of where you believe the state 
of the art to be in coal-fired generation and where you expect it to be 
in 10 years? Assuming a CO2 price on the order of the MIT 
Future of Coal report and increased RD&D support, when do you think we 
may reasonably be able to deploy a variety of near-zero CO2 
emission technologies?
    Answer. Today's state-of-the-art for coal-fired generation in the 
U.S. is supercritical pulverized coal combustion. Additionally, there 
are two existing commercial Integrated Gasification Combined Cycle 
(IGCC) plants, originally designed for coal, that are presently 
operating on petroleum coke and pet-coke/coal mixtures. In 10 years we 
expect to see coal-based ultra-supercritical pulverized coal and IGCC 
plants commercially deployed in the U.S.
    Assuming a CO2 price on the order of the MIT Future of 
Coal report\1\, and a series of annual target funding levels that will 
encourage the continued development of enabling technologies, a process 
intensification effort that will permit the combination of several 
processes into a single step, and a near doubling of the number of 
demonstrations of new Carbon Capture and Storage (CCS) plants over the 
next 20 years, we would expect to accelerate by about 20 years (i.e., 
by 2030) the date by which all demand for new coal-fueled power plants 
in the U.S. can be economically met with CCS plants. Starting by 2020, 
it is expected that an increasing number of advanced CCS plants would 
be deployed. To ensure this result, we must begin now and continue 
through 2020 the demonstrations needed to drive CCS to the lowest 
possible cost for all U.S. coals, and to make this an attractive option 
for large, coal-dependent developing nations.
---------------------------------------------------------------------------
    \1\ Text drawn from MIT Future of Coal report, page XI, paragraph 
3, reads ``We estimate that for new plant construction, a 
CO2 emission price of approximately $30/tonne (about $110/
tonne C) would make CCS cost competitive with coal combustion and 
conversion systems without CCS.''
---------------------------------------------------------------------------
    Examples of enabling technologies currently under development 
include advanced pressurized solid-feed systems, oxygen-blown transport 
gasifiers, ion-transport membranes, high-performance desulfurization, 
hydrogen turbines, solid-oxide fuel cells, and advanced CO2 
separation, capture, compression, injection, and Modeling, Monitoring, 
and Verification (MMV) technologies.
       Responses of Carl Bauer to Questions From Senator Domenici
    The costs of goods and services required to build power plants have 
increased significantly in recent months.
    Question 3a. Can you quantify these increases for us, both for 
next-generation plants as well as traditional designs?
    Answer. New traditional plants are being adversely impacted by 
increases in costs, resulting from the lack of availability of 
materials and the lack of availability of skilled construction labor. 
Next-generation plants are likewise impacted by similar increases, and 
are further impacted by the costs of insurance associated with the 
requirement for performance wraps or guarantees that accompany the 
inherent risk of deploying new and unproven technology (current 
estimates for a next-generation IGCC plant performance guarantee are on 
the order of 35% of total plant construction cost), as well as the 
increased costs of construction associated with building redundancies 
into new plant designs to ensure defined plant performance and economic 
targets can be met. Furthermore, advanced coal plants, including IGCC 
and pulverized coal (PC) based systems with carbon capture, will 
require operations and maintenance personnel with significantly 
different skill sets, compared to those that support traditional 
facilities. Over the past 5 years, it is estimated that the costs of 
traditional pulverized coal combustion plants have gone up in the 
neighborhood of 75% to 100%, from approximately $1,200/kWe to 
approximately $2,000 to $2,500/kWe.
    Over the past 5 years, it is estimated that the costs of next-
generation coal-fueled plants have gone up in the neighborhood of 200% 
to 250%, from approximately $1,500/kWe to approximately $3,200/kWe 
(recent Duke Power IGCC estimate) to $3,700/kWe (recent AEP IGCC 
estimate).
    Question 3b. Are advanced clean coal plants disproportionately 
impacted by this trend of increasing costs?
    Answer. Yes, as a consequence of the need for both performance 
guarantees and risk mitigating redundancies, as explained above. Also, 
acquiring operations and maintenance resources with appropriate 
education and skill sets will result in higher personnel costs compared 
to traditional designs.
    Question 4. Can you quantify for us the costs of construction for a 
plant with the best environmental technologies that are currently 
available at commercial scale as they compare to ultra-supercritical 
plants and other advanced plants that would, in fact, incorporate some 
form of carbon dioxide capture and storage?
    Answer. NETL recently published a baseline study forecasting the 
``overnight'' construction costs of power plant technologies that could 
be built and operated in the 2012 to 2015 timeframe.\2\ The information 
presented here is derived from the results of this study.
---------------------------------------------------------------------------
    \2\ The ``overnight'' construction cost includes costs for detailed 
engineering design, project management, construction labor, process 
equipment, on-site support facilities and infrastructure, and process 
and project contingencies.
---------------------------------------------------------------------------
    Today's best estimate of the overnight construction cost for an 
ultra-supercritical coal-fueled plant, outfitted with those 
technologies necessary to meet all applicable environmental 
regulations, is estimated at $1,641/kWe. Today's best estimate of the 
overnight construction cost for an IGCC plant, outfitted with those 
technologies necessary to meet all applicable environmental 
regulations, is estimated at $1,841/kWe. For an ultra-supercritical 
pulverized coal plant with carbon capture and storage technology, the 
overnight construction cost is estimated at $2,867/kWe, and for an IGCC 
plant with carbon capture and storage technology the overnight 
construction cost is estimated at $2,496/kWe.
    Estimates for the carbon capture and storage plants provided above 
are based on plants designed for approximately 90% carbon capture. It 
is also important to note that the overnight construction cost 
estimates presented do not include interest during construction, 
project-specific owner's costs (e.g., costs associated with feasibility 
studies, site/infrastructure improvements, permitting, legal services, 
and financing) or any performance guarantees. Because plants equipped 
with carbon capture would be ``first-of-a-kind'' facilities, these 
added costs may be substantial.
    A final observation here is important. Ultra-supercritical plants, 
whose principal advantages are higher efficiency and lower coal fuel 
consumption, are more economically amenable to our European neighbors, 
since Europe tends to experience high coal prices, relative to the 
United States where coal prices tend to be both less volatile and less 
expensive. As a result, in markets where no incentives are present that 
encourage carbon mitigation, there is little, if any, economic 
advantage to deploying ultra-supercritical technology. Evidence of this 
assessment, as it applies to U.S. markets, is present in that over the 
past 20 years, 49 sub-critical plants (>50 MW) and 3 supercritical 
plants have been built. During this same 20-year period, no ultra-
supercritical plants were built in the U.S., nor are we aware of any 
plans for their construction. Finally, as of October 2007, there are 24 
sub-critical and only 4 supercritical power plants that are either 
under construction or in the permitting phase, and we are not aware of 
any plans for ultra-supercritical plants.
                                 ______
                                 
  Responses of Jeffrey N. Phillips to Questions From Senator Bingaman
    Question 1. You give a hopeful picture that ``learning-by-doing'' 
in a commercial setting will lead to significantly reduced costs over 
time for technologies. Are there any inherent incentives for private 
actors to lead in deploying new technologies? Are the efficiency gains 
and increased certainty regarding future regulation ever enough to push 
for leading edge design on their own?
    Answer. In short, the general answer is ``yes,'' but in the case of 
carbon capture and storage (CCS), a combination of private initiative 
and public sector incentives is likely to be the most effective means 
of achieving the necessary design advances in a timely manner.
    Cost reduction through ``learning by doing'' is real, as evidenced 
by the industry's history with other environmental controls, but in the 
case of SO2 scrubbers, for example, regulatory requirements 
were clear, first through the Clean Air Act's New Source Performance 
Standards and later through the Acid Rain provisions of the 1990 Clean 
Air Act Amendments. With respect to greenhouse gas (or CO2) 
emission regulations, while their prospect seems clear, their nature 
and timing are still big unknowns. Getting initial installations of 
advanced technologies in place, before regulations take effect, to 
start the learning-by-doing process--getting costs down before large 
investments are required for compliance--will take ``beyond market'' 
incentives. The Energy Policy Act of 2005 sought to address this, but 
even some projects that had been awarded investment tax credits have 
recently been shelved due to regulatory uncertainty risk for 
CO2.
    Other ``institutional factors'' and traditions have made the power 
industry prudent with respect to investments in not-yet-proven 
technologies. For example, policies in some states prohibit public 
utilities commissions from allowing cost recovery on investments in 
emission controls exceeding the requirements of current regulations. 
Also, coal has historically been a relatively inexpensive fuel in the 
United States, which has limited the amount of capital investment and 
risk that could be justified for unproven high-efficiency technologies. 
Further, the economics of power generation (and public scrutiny) always 
place a high premium on reliability. Because the reliability of a new 
technology is difficult to predict in advance of real-world 
application, there is an incentive to be the ``second in line'' when it 
comes to buying new technology. Thus, in EPRI's opinion, leading-edge 
designs such as the extremely efficient pulverized coal plants with 
integral CCS outlined in EPRI's UltraGen Initiative, and the new 
generation of integrated gasification combined cycle units suitable for 
(or with) CO2 capture, will not be easy to implement without 
industry and government risk sharing. Programs such as the Department 
of Energy's Clean Coal Power Initiative can help spread risk and may 
``tip the scale'' in favor of new technology investment. By encouraging 
collaborative funding of demonstration projects, EPRI also helps spread 
the risk of testing new technologies. Each power generator contributes 
a small fraction of the total cost, yet receives the knowledge gained 
from the tests.
    Regulatory flexibility during the period of new technology 
introduction can also help. An example of success in this area was the 
incentives for early adopters of selective catalytic reduction (SCR) 
systems for NOX control. ``Allowance banking'' and other 
provisions encouraged several power companies to install SCR units 
before the mandatory compliance date, allowing them to resolve 
reliability and performance issues (such as the unexpected problem of 
catalyst plugging by large-particle ash) while they could still legally 
turn off the units during normal operations.
    Question 2. In your description of your proposed UltraGen Project, 
you include the option of capturing 25% of the CO2 from the 
plant. Why only 25%? Why wouldn't you capture more CO2 in 
this project?
    Answer. Please allow me to clarify that we propose capturing 90% of 
the CO2 from 25% of the flue gas at a new, large (800 
MWe net) clean and eficient pulverized coal plant. Capture 
of 90% of the CO2 from the inlet flue gas is the goal of the 
Department of Energy and many technology developers. Treating 25% of 
the gas flow from a very eficient plant (equivalent to 200 
MWe ) corresponds to a volumetric flow rate equal to the 
expected rating of an early commercial post-combustion CO2 
capture module. Thus, choosing to treat 50% of the gas flow would mean 
testing two of the same modules rather a single larger ``more 
commercial'' module. As a result, the research value would be only 
marginally improved while the cost of the CO2 capture 
demonstration element would nearly double. Were adequate funding for 
two test modules available, a better research strategy would be to put 
them on two different plants using different coals (and UltraGen is 
open to this possibility).
    Further, the scale-up to a 200 MWe CO2 
absorber module represents an ambitious challenge in its own right. The 
largest post-combustion unit in current operation captures 500 tons of 
CO2 per day (from a steam reformer used in the production of 
urea fertilizer). About 200 MWe worth of flue gas from our 
proposed UltraGen I unit corresponds to more than 4000 tons of 
CO2 per day, an eightfold increase. We will use an advanced 
amine solvent to reduce energy penalties, and demonstrate thermal 
integration of the solvent reboiler (the step that releases 
CO2 from the solvent for subsequent clean-up and 
compression) with other plant processes to further reduce energy 
penalties, and hence operating costs. The follow-on UltraGen II project 
will treat at least 50% of the flue gas with a 90% CO2 
removal process (potentially using a further improved solvent that 
allows for a larger single absorber module). The ultimate commercial 
plant, embodied in UltraGen III, will treat all of the flue gas with a 
90%+ CO2 removal process (or could possibly demonstrate oxy-
combustion CO2 capture).
    Question 3. In your analysis of the technical potential for 
emissions reductions from CO2 capture and storage, did you 
include retrofits of existing plants for CO2 capture and 
storage? If not, why not, and what would be the impact if we did?
    Answer. The economics of CO2 capture are best on plants 
that operate at high capacity factors (i.e., baseload). As new coal 
plants come on-line, they are dispatched in baseload mode while some 
existing plants are moved to load-following service. Thus, EPRI's 
``Prism'' analysis assumed all new coal plants coming on-line after 
2020 would be the first to be built with CCS. Given differences in the 
generation mix serving regional grids and the likely variations in the 
compliance strategies ultimately adopted by U.S. power generators in 
response to CO2 regulations, we expect that some existing 
units may be retrofitted with CCS. But because costs for retrofits are 
higher and energy penalties greater, to be conservative in the Prism 
analysis, we assumed that existing plants underwent efficiency upgrades 
but not conversion to CCS.
    Research by EPRI and others suggests that retrofitting 
CO2 capture equipment to existing coal plants not originally 
designed for such systems would be very costly, ranging from 
``considerably more expensive'' than the incremental cost of 
incorporating CO2 capture equipment in new plants up to 
situations where it would be prohibitively expensive (virtually 
impossible) due to lack of available space in the plant. With respect 
to the latter, up to 6 acres at the back end of the plant is needed for 
a 500 MW unit. In addition, the energy impacts (in terms of output and 
efficiency reduction) are greater for retrofits than for new plants. 
EPRI has not conducted a plant-by-plant analysis to ascertain the 
number of existing units that could, in theory, be converted to CCS, 
and thus cannot estimate the CO2 emissions reduction 
potential (or cost and capacity reduction) of such retrofits. Instead, 
EPRI's analysis of the potential CO2 emissions reductions 
from CCS focused on the incorporation of CO2 capture into 
the sizeable new fleet of advanced coal plants (as projected by the 
Energy Information Administration) built to the growth in electricity 
demand.
    Question 4. We talked a bit about the order in which additional 
power is ``called up'' to meet demand, with the effect being that lower 
CO2-emitting natural gas generation is used less due to high 
natural gas costs. Have you done any analysis to determine the 
potential effects on energy prices and technology deployment if some 
regulatory mechanism were put in place to mandate increased use of 
lower-emitting generation?
    EPRI hasn't conducted such an analysis for today's generation mix, 
but as part of the background pap er for the EPRI 2007 Summer Seminar, 
``The Power to Reduce CO2 Emissions: The Full Portfolio'' 
(see http://epri-reports. org/DiscussionPaper2007.pdf), EPRI ran 
scenarios for 2050 in MERGE, a general equilibrium economic model used 
for analyzing the cost of CO2 emissions mitigation. Although 
this isn't a dispatch model, it can be used to estimate the composition 
of the generation mix and wholesale price of electricity when various 
potential solutions for reducing CO2 emissions are allowed 
or not allowed. The most dramatic difference in wholesale price 
occurred when the ``full portfolio'' scenario was compared with one in 
which new coal plants with CCS and new nuclear plants were not allowed. 
In the latter scenario, natural gas became the dominant fuel for 
generation and thus the comparison with the full scenario (which is 
rich in coal with CCS and nuclear) is somewhat of a surrogate for the 
question you pose. Our results showed that the 2050 wholesale price of 
electricity was more than double in the gas-dominated scenario versus 
the full portfolio scenario. We also found this price increase would 
have a considerable adverse effect on the U.S. economy.
    Question 5. The MIT Future of Coal report pegged $30/ton of 
CO2 as the point at which we may expect widespread 
deployment of developed capture and sequestration technologies. This 
assumes the technologies are demonstrated and ready for mass 
deployment. Throughout this hearing we have heard of the great 
potential technologies but that significant hurdles remain, especially 
in getting large-scale initial deployment. Has EPRI done any analysis 
of what type of price level for CO2 would be needed to make 
early adoption and initial demonstration of these technologies an 
economical proposition for generators?
    Answer. Sadly, ``50'' is the new ``30.'' The $30/ton-CO2 
figure generally predates the recent run-up in costs for capital 
projects due to record high commodity prices and tighter U.S. markets 
for craft labor given post-Katrina rebuilding. Illustrative of this 
point, the Chemical Engineering Plant Cost Index increased by about 35% 
from June 2003 to June 2007, after five years of virtually no change. 
In a recent paper prepared for the California Energy Commission, MIT 
estimated the avoided cost of CO2 for new baseload-duty 
coal-based plants in California at about $50 per metric ton when a 
modest contingency for first-of-a-kind technology was included. On this 
same basis, the avoided cost of CO2 in the traditionally 
lower-cost Gulf Coast area was about $40 per metric ton. Analyses by 
EPRI's ``CoalFleet for Tomorrow'' program suggest that the price of 
CO2 needed to make a new coal plant with CCS competitive (on 
a levelized cost-of-electricity basis) with an existing clean coal 
plant buying emission allowances or paying a carbon tax is now almost 
$70 per metric ton.
   Responses of Jeffery N. Phillips to Questions From Senator Sanders
    Question 6. In your testimony, you predicted that the efficiency of 
coal-fired electric power plants will increase over the next two 
decades from the current 33% efficiency to as high as 44-49% efficient 
by 2025, as more high-technology systems are employed, such as ultra-
supercritical pulverized coal. You also mentioned that this assumes no 
carbon dioxide capture, but with CO2 capture, these 
efficiencies would be lowered to 39-46%, a penalty for the extra energy 
needed for capture of 3-5%. These efficiency losses reflect a 90% 
capture of CO2, but not the compression or transportation of 
the CO2. If one were to incorporate the compression, 
transportation, and sequestration values, how much more of a loss of 
efficiency would result? Is it fair to say that this better technology 
will allow us to still see increased efficiencies, over the current 33% 
efficiency, while at the same time completely taking care of carbon 
emissions with carbon capture and storage?
    Answer. Please allow me to clarify that the ``with capture'' 
eficiency values reflect the energy penalties for both CO2 
capture and compression, but as you correctly point out, not the losses 
associated with transportation and injection. Please also allow me to 
clarify that the 33% eficiency value is an overall average for the 
current fleet of coal plants, some of which are 50 years old or more 
and some of which are operated in a less efficient (but grid support 
critical) load-following mode. With those qualifiers in mind, the 
answer to your question is ``yes.'' We foresee new baseload advanced 
coal plants with CCS (including the efects of a modest transportation 
distance and injection) having eficiencies exceeding those of the 
current fleet average. Of course, this won't happen automatically. A 
sustained, accelerated RD&D program involving private and public sector 
stakeholders will be required to bring the promise of ultra-eficient 
clean coal plants with CCS to commercial fruition in a timely manner. 
Existing research programs and roadmaps by DOE, EPRI, equipment 
suppliers, industry groups such as the Coal Utilization Research 
Council, and others provide the foundation for the necessary 
collaborative and proprietary efforts.
    In calculating the efficiency penalty for CO2 
compression, EPRI assumes the use of an interstage-cooled compressor 
with a final delivery pressure of 2200 pounds per square inch (psi). 
This impact is typically reported in combination with the efficiency 
penalty for capture because both take place within the plant boundary. 
The efficiency impact of transportation depends on the distance the 
CO2 must be shipped and the diameter of the pipeline. Unless 
unusually long distances or undersized pipelines are involved, the 
impact is typically small relative to the energy penalty for capture 
and compression. Similarly, the additional energy requirements for 
injection are small given that pipeline delivery pressure is already at 
2000+ psi.
    Question 7. You testified that you predict only a 10% increase in 
the cost of electricity by 2025 if carbon is captured and stored. Does 
this estimate include just the capture of CO2 or the full 
capture, compression, transportation, and storage?
    Please allow me to clarify that EPRI's goal for post-combustion 
CO2 capture is an energy penalty of no more than 10% and a 
levelized cost-of-electricity increase of no more than 20%. This 
reflects the cost of CO2 capture and compression, but not 
the cost of transportation and storage because these can be highly 
variable depending on how far a power plant is from a storage site and 
the permeability of the target formation. Transportation and storage 
could add another $5/MWh or more to the levelized cost-of-electricity.
    Question 8. You also mentioned that if liquefied carbon dioxide is 
not cleaned of sulfur or other contaminants before it is stored 
underground, it may clog up the pores in the underground rock, so that, 
instead of a 30-year storage capacity, you may only get a five-year 
storage capacity. Can you explain at what levels of contamination this 
is likely to occur? Does it depend on the kind of rock or saline 
substrata that the CO2 is being sequestered in?
    Answer. Although there is currently some uncertainty over the 
impact of CO2 impurities on subsurface rocks during 
injection and over the course of long-term storage, and further 
research is warranted, the scenario of plugging to the point that 
injection was no longer possible, as posed in the question, is not 
considered likely by researchers at Lawrence Berkeley National 
Laboratory.
    The most likely sulfurous impurities in a CO2 stream 
captured at a coal-fired power plant, hydrogen sulfide (H2S) 
and sulfur dioxide (SO2), will form acids upon interaction 
with subsurface moisture, and those acids can dissolve soluble 
materials such as calcium minerals (which actually increases porosity). 
Although reaction products can subsequently re-precipitate out of 
solution, any associated deposition is likely to be small relative to 
the aggregate pore cross-sectional area of the injection zone.
    Traces of H2S have been shown to have a beneficial 
effect when the CO2 is injected into a depleting oil field 
for enhanced oil recovery.
  Responses of Jeffrey N. Phillips to Questions From Senator Domenici
    Question 9a. The timeline in your testimony indicates a belief that 
the most substantial reductions in CO2 emissions from coal 
consumption will not occur until post-2020. What steps should we be 
taking in the interim, however?
    Answer. As noted in my response to Question 10, technologies to 
improve the efficiency of existing coal-fired units are available today 
and their application offers an option (barring New Source Review 
issues) to begin curbing CO2 emissions. The substantial 
CO2 reductions from ultra-eficient coal plants and CCS shown 
taking place after 2020 will only be possible if we accelerate and 
augment current RD&D programs in a comprehensive, well-coordinated 
manner with sustained funding commitments from the private and public 
sectors between now and then.
    To enable commercial deployment of CCS by 2020, about a half dozen 
large-scale CO2 storage demonstrations must be conducted in 
various geologic settings; CO2 capture technologies need to 
be scaled up and demonstrated in pre-combustion, post-combustion, and 
oxy-combustion configurations; and CO2 pipeline networks 
will need to be constructed. Each of these activities represents a 
substantial set of capital projects, costing hundreds of millions to 
billions of dollars, and taking five or more years with some projects 
needing to be coordinated or sequenced with others. Similarly, RD&D to 
improve the cost, performance, and reliability of advanced power block 
technologies for IGCC and USC PC units using various coal types 
(bituminous, subbituminous, lignite) needs to be conducted 
expeditiously over this same timeframe. EPRI believes that integrated 
CCS demonstrations provide the dual benefit of proving CO2 
capture and storage technologies to be safe and effective while 
addressing real-world multi-agency permitting and monitoring/
verification issues. For long-term CO2 storage, important 
legal and regulatory uncertainties need to be resolved before 
widespread commercial deployment can take place.
    Question 9b. In the context of energy security, and our nation's 
desire for reliable and affordable energy, do you believe it is wise to 
oppose the construction of new coal plants even if they employ the 
best, commercially available, environmental technologies?
    EPRI believes that even with aggressive investment in conservation 
and end-use energy eficiency improvement (which we support), a 
substantial number of new power generating units will be needed to meet 
demand growth and to replace retiring units. We believe that in the 
economic interest of ratepayers and in the interests of national 
security, a full and diverse portfolio of generating resources--
including new state-of-the-art coal plants--is our best strategy.
    Domestic resources including nuclear, renewables, and fossil fuels 
(particularly natural gas and coal) as well as imported resources like 
liquefied natural gas and oil will play different roles in different 
parts of the country. Coal is our largest domestic fuel resource, it 
provides over half our electricity today, and we project that it will 
be needed to provide affordable power in the future. Today's new coal 
plants are more efficient and much cleaner than older units and produce 
less CO2/MWh. EPRI studies have shown that without both new 
coal with CCS and nuclear power in the portfolio of solutions to the 
challenge of CO2 reductions, wholesale power prices will 
more than double and the U.S. economy will shrink (relative to its size 
with the full portfolio of CO2-reducing technologies) by $1 
trillion.
    Question 10. As we look at the existing fleet of coal-fired 
electrical generation, and ways to reduce the carbon dioxide emissions 
from it, what do you believe are the costs and benefits of the choice 
between efficiency improvements versus seeking to retrofit these plants 
with carbon dioxide capture technologies?
    Efficiency improvements and CCS retrofits are compatible 
approaches, not alternatives. Investments in efficiency improvement 
today help reduce (albeit modestly) the cost of future retrofit of 
CO2 capture systems.
    Technologies for efficiency improvement are available today and can 
be applied in the near-term. Some are relatively low cost and easy to 
implement, providing modest improvements, whereas additional options 
providing greater improvement entail more significant equipment 
modifications at greater cost. Such upgrades typically provide economic 
benefits unless they are burdened with costly pollution control add-ons 
as a result of New Source Review (NSR) requirements. The resulting 
reduction in CO2 emissions is significant but limited--
approximately a 2% reduction in CO2 emissions for every 1 
percentage point improvement in plant efficiency. A policy approach 
that enabled plant modifications for efficiency improvement without 
incurring the costs of NSR emission control additions/upgrades could 
encourage investments yielding CO2 reductions of 5-10%.
    Because CO2 capture equipment is sized on the basis of 
the volume of flue gas to be treated, efficiency improvements reduce 
its cost by reducing the volume of flue gas produced per MWh generated. 
Overall, however, CCS retrofits will remain major capital projects 
requiring substantial investments and equipment additions--indeed, some 
plants may not even have room for it. Where feasible, CCS retrofits 
have the potential for major CO2 emission reductions, in 
theory up to about 90%. Plant output and/or efficiency are reduced in 
the process, and retrofits will not generally offer the same 
possibilities as new plants for optimized ``heat integration'' to 
reduce these impacts.
    Because it will take time to build commercial-scale CO2 
capture systems for demonstration, inject significant volumes of 
CO2 and monitor/verify its subsurface behavior to assure 
safe and effective storage, it will take considerably longer to apply 
CCS than to apply efficiency upgrade measures. Accordingly, efficiency 
improvements can have an impact on electricity sector emissions sooner 
than can CCS.
    Question 11a. Do you believe a resistance on the part of state 
utility commissions and other regulatory bodies to allowing cost 
recovery for more expensive clean coal technologies has impeded 
technological progress?
    Answer. We believe the charter of public utility commissions in a 
number of states requires consideration of the least-cost strategy that 
satisfies new generating capacity needs in the interest of the 
ratepayers. This may limit allowance of higher-cost strategies that 
serve other objectives, such as control of currently unregulated 
CO2 emissions.
    Question 11b. Is this an issue that the Institute has looked into 
in any detail?
    Answer. No, EPRI has not examined this potential obstacle in 
particular.
                                 ______
                                 
     Responses of Jim Rosborough to Questions From Senator Bingaman
    Question 1. You envision both carbon capture and gasification of 
biomass with coal to reduce the carbon footprint of a plant. How do you 
estimate the lifecycle greenhouse gas (GHG) emissions of such a plant 
would compare to a plant using conventional feedstocks?
    Answer. Mr. Chairman, we believe that the reduction of GHG 
emissions requires a multi-faceted approach. We can briefly describe 
our evolving position on this subject as follows:

    Choice of feedstock is an important component of the solution, and 
biomass utilization provides GHG reduction benefits at two points: (1) 
during feedstock conversion, where ``plant emissions'' occur, and (2) 
during downstream use of product.

          (1) During feedstock conversion, CO2 is generated 
        as a natural by-product of hydrocarbon processing. We pursue an 
        efficiency campaign to minimize the CO2 generated in 
        our processes (``maximizing carbon efficiency''). For the 
        remaining CO2 produced, the percentage of biomass as 
        feedstock directly ofsets or ``neutralizes'' a corresponding 
        percentage of CO2. This is consistent with the view 
        that CO2 generated from renewable feedstocks is GHG 
        neutral.
          (2) The percentage of biomass in the feed will also translate 
        into a corresponding percentage of ``renewable carbon'' in the 
        product. If the last fate of such product were to be 
        combustion, the percentage of renewable carbon in the product 
        would generate a corresponding percentage of ``GHG neutral'' 
        CO2.

    A specific example is required to calculate exactly what the 
expected benefits would be, but the above logic indicates you get a 
``double benefit'' from biomass utilization on a life cycle basis.
    We believe that maximizing carbon efficiency (minimizing 
CO2) requires industry to integrate processes, continue to 
improve in operational disciplines and practices, and make advances in 
the practical utilization of alternative feedstocks such as biomass.
    Question 2. You mentioned biomass as a potential feedstock along 
with coal. We've heard of gasifiers operating with some percentage of 
municipal solid waste and other materials; are these likely to be 
suitable for your process as well?
    We believe so. Gasification enables virtually any hydrocarbon 
containing material to be utilized as a feedstock. The list includes 
municipal solid waste (MSW), post-consumer plastic waste, industrial 
wastes, municipal sewage sludge, as well as various kinds of biomass. 
We are evaluating a whole slate of technologies that can contribute to 
the utilization of these materials, and feel confident that with our 
engineering capabilities, we can make this work technically.
    The primary hurdles are centered on logistics and economics. The 
question we ask is, ``What do the economics of these technologies look 
like, and are they practical for improving our competitiveness in a 
global context?'' To answer this question, we believe that partnership 
with government to assist in the acceleration of development and 
mitigation of initial risk is imperative to making the concept into a 
reality.
    Question 3. You generally seem to assume co-production of liquid 
fuels at an industrial gasification plant. Is this a necessity either 
because of physical design or economically? Assuming integration of 
heat recovery and cogeneration of power in each case, can you compare 
economics of a plant producing chemicals and plastics only to a plant 
that would produce a mix of products and liquid fuels?
    Answer. Maximizing carbon eficiency is our goal. The more one 
integrates complementary industrial processes, the better. Fuels are 
not necessarily a critical part of the process, depending on the plan, 
consumer needs, market realities, etc. Our industry benefits from fuels 
production because those processes also produce chemical feedstocks as 
a by-product. Whether or not one chooses to make fuels in a 
polygeneration setting, the economics depend on capital cost, operating 
and logistics costs, and market conditions.
     Responses of Jim Rosborough to Questions From Senator Domenici
    In many ways, the chemical industry is more familiar with 
CO2 capture than the electric utilities.
    Question 4a. What opportunities do you believe exist for the two 
industries to collaborate in a carbon-constrained world?
    Answer. Dow has engaged in the polygeneration of chemicals, 
plastics, and electricity for the better part of our 110 years as a 
company. There is considerable opportunity for collaboration with 
electric utilities, and in fact we have a history of such activity. A 
key point we observe as we look forward to solve GHG emissions 
challenges is this: if you make only electricity, 100 percent of the 
carbon is converted to CO2. If you make chemicals together 
with electricity, less than half of the carbon is converted to 
CO2.
    Question 4b. Do you believe it is appropriate, or you might say ``' 
`fair', to require or ask the utility industry, which has significantly 
less experience with these technologies and processes, to abide by the 
same timeline that your industry is likely to be capable of?
    Gasification is essentially a chemical process, and we are expert 
in operating chemical processes for maximum efficiency and 
effectiveness. We don't see ourselves as having expertise in commercial 
power generation and distribution, but we believe we can be helpful in 
bringing our process knowledge into these projects, in a way that 
shouldn't disrupt the timeline.
    Collaboration with electric utilities is not unlike the joint 
venture model that we commonly practice, with each participant bringing 
diferent skills to the party. One of the important issues to recognize 
is that the world's power plants aren 't yet capture ready. The world 
needs a solution for legacy plants, and chemistry can be a part of that 
solution.
      Responses of Jim Rosborough to Questions From Senator Corker
    Question 5a. As the Senate prepares to debate cap-and-trade 
legislation this fall, please give me your perspective on how we should 
contemplate and deal with coal in the short-term during that debate, 
apart from the incentives that you laid out in your testimony.
    Answer. As the most abundant and lowest cost energy and chemical 
feedstock in the United States, we believe that coal must have a place 
in our alternative feedstocks portfolio moving forward. Dow is 
committed to working with industry to determine and implement the 
cleanest, most effective and eficient technologies for utilizing coal, 
both in the short term and the long term.
    We also point out that the United States must avoid a renewed 
``rush'' to natural gas. We are already observing the highest natural 
gas prices and volatility in history. Further exacerbating the already 
tight supply/demand balance of natural gas in the US would be 
detrimental to the economy and further strain the already threatened 
competitiveness of US industry.
    We believe that a ``phase in'' approach for standards is the best 
way to enable affordable progress. Progress should then trigger 
stricter standards, and the process can be repeated. Multiple problems 
require our attention, not the least of which are the need for retrofit 
solutions for carbon capture at conventional natural gas and coal-fired 
power plants. The carbon constraints on our energy mix must acknowledge 
this development curve as we move forward, for any and all feedstock 
choices.
    Question 5b. Keeping in mind the need to rely on coal as part of 
our future energy mix, what do you think are appropriate emissions 
targets in what amount of time, such that we challenge industry without 
being unrealistic based on what is technologically possible?
    Answer. We're still evaluating details. We know that successive 
generations will demonstrate improvements, i.e., the third plant will 
perform better than the second, which will perform better than the 
first. We believe that a CO2 emissions standard at 75% of a 
conventional oil refinery's life cycle footprint is feasible. We might 
need to establish a lower hurdle at first, and apply a graduated 
standard with a look-back provision so the learnings from the most 
efficient plants are applied to the early movers. What is critical to 
consider now is, how will the government and industry partner together 
to accelerate the necessary experience we need to determine the best 
approach.
                                 ______
                                 
      Responses of Don Langley to Questions From Senator Bingaman
    Question 1. Developers of new power plants tell us they cannot 
commit to deploying a new technology without a commercial performance 
guarantee from the vendor. You mention that your company is involved in 
developing a 300 megawatt oxy-coal combustion plant with CO2 
capture. Does that mean you are able to issue a guarantee on this 
technology at that size, or is the developer willing to go without the 
guarantee?
    Answer. This situation could best be characterized as ``semi-
commercial.'' The SaskPower project is a leading edge endeavor to 
achieve positive climate change while using local natural resources in 
a socially responsible manner. The OxyCoalCombustion (OCC) process 
utilizes industry-proven enhanced technologies based on years of 
successful implementation into the commercial market. As such, major 
items such as the steam generator, turbine and air separation unit can 
all be offered with commercial guarantees and warrantees. Integrating 
of these technologies into the OCC process and delivering 
CO2 to a permanent storage site have first-of-a-kind (FOAK) 
risks associated with the process, and they are being borne mostly by 
the owner. Additionally, the presence of FOAK risk naturally leads to 
contingent designs (multiple solutions or pre-planned modifications to 
be implemented based upon first experiences) that also add costs to a 
project. These are also being borne by the owner. In the US, these two 
added risks are areas where the Federal government could step in and 
provide financial support that would lead to faster development and 
deployment, and put the US into a world-wide lead in carbon management.
    Question 2. It seems a bit like a commercial performance guarantee 
requires demonstration of the technology at scale but no commercial 
developer is willing to risk implementing the technology at scale 
without a performance guarantee. This sounds a bit like a catch-22. Is 
there an effective way past this problem? Are you aware of how other 
countries are addressing this issue?
    Answer. There will never be a substitute for the learning-by-doing 
final phase of technology development. The electric utility industry is 
the most capital intensive industry in the US and, therefore, at-scale 
demonstrations are a required precursor for both the technology 
provider and the technology adopter. Enabling large demonstration 
projects (in this case, projects that capture between 500,000 and 
1,000,000 tons per year of CO2) is the first step in 
breaking through the implied conundrum. Following a demonstration, the 
technology then is validated at commercial scale by an early adopter 
who has some incentive or special risk mitigation structure to take 
this scaleup risk. With validation of the technology, performance 
assurances would become available enabling market forces to sort out 
the winners in a true commercial context. Cost reductions and capital 
efficiency come after the initial deployment and with continued use of 
the technology and processes.
    Like the DOE, many other governments (EU, Japan and Australia) 
provide funding for fundamental research and pilot testing of new 
technologies. The final phase of first commercial use stills tends to 
fall to the first owner (Utility) to take the risk. Many of those 
Utilities may still receive government support that is unseen (Japan), 
or simply be large multi-national companies that can be exposed to the 
risk (RWE and Vattenfall). The risk associated with the first 
deployment of full carbon capture and storage power plants is one of 
the largest undertakings ever planned for the electricity generation 
infrastructure. It is, therefore, essential that the Federal government 
provide the leadership and support for that final step for US first 
adopters and pioneers.
      Responses of Don Langley to Questions From Senator Domenici
    Question 3a. Your testimony clearly predicts that commercial-scale 
carbon capture and storage will not be viable until the year 2020. What 
do you believe we should be doing in the interim, in addition to 
research and development, to reduce carbon dioxide emissions from coal-
fired electricity?
    Answer. The Coal Utilization Research Council (CURC) has put 
together a near-term program to address CO2 emissions from 
coal-fired plants. First, improving the efficiency of the existing 
fleet would have an immediate payback in reduced emissions. There are 
many plants that could make improvements and upgrades that would lead 
to less coal consumed for the power output. One such upgrade could be 
the new coal drying technology developed recently with them support of 
the DOE in North Dakota. Secondly, enact an investment credit or 
production credit for those who add up to 10% biomass co-firing to 
their existing plants. With biomass considered a carbon neutral fuel, 
there would be an immediate reduction of CO2 emissions. The 
addition of this amount of biomass requires a separate fuel handling 
and delivery system, which is a capital investment. Finally, 
ultrasupercritical (USC) power plants are ready to deploy today, and 
they can be designed with future carbon capture in mind. These plants 
would reduce CO2 emissions 15-17% below the current fleet-
wide average, and coupled with normal retirements of older, less 
efficient plants, can have an immediate impact in the near term.
    Question 3b. Do you predict availability of ultra-supercritical 
plant designs in the year 2020 also, or is commercial application of 
this technology more imminent?
    Answer. New ultrasupercritical power plants are available today, as 
seen in the state-of-the-art plant that AEP is planning to build in 
Arkansas, which will be the first USC coal unit ever built in the US. 
This technology will reduce CO2 emissions by 15-17% over the 
fleet-wide average. The plant will operate with a steam temperature of 
1115 F (600 C). The technology development path that we are on, with 
support from the DOE, is to build power plants at 1400 F (760 C), 
similar to the path Japan and the EU are on. This advanced 
ultrasupercritical plant design would have 28-30% less CO2 
emissions than the current fleet. To meet a date of 2020, more work has 
to be done, and additional Federal government support is needed to push 
this technology into full deployment and market acceptance, starting 
with the completion with the material development program, followed by 
the first demonstration plant.
       Responses of Don Langley to Questions From Senator Corker
    Question 4a. As the Senate prepares to debate cap-and-trade 
legislation this fall, please give me your perspective on how we should 
contemplate and deal with coal in the short-term during that debate, 
apart from the incentives that you laid out in your testimony.
    Answer. New plants should be capture-ready following a rigorous 
guideline similar to that proposed by the IEA-GHG Programme. This will 
ensure that there is no carbon-lock in, and that efficient use of our 
natural resources is enabled, thus maintaining our world leading 
economy and manufacturing base. Ultrasupercritical power plants should 
be deployed to realize the benefits of the higher efficiency operation 
and continued reduction in all emissions. Existing plants should 
evaluate the benefits of efficiency improvements and co-firing of 
biomass. Along with all these, the continued deployment of coal fired 
power plants is critical to our economy and energy security. We cannot 
take a hiatus or implement a moratorium on new coal and push our 
reliance into the volatile natural gas market (which competes with our 
manufacturing base and home heating), or the dangerous and uncertain 
world of imported LNG.
    Question 4b. Keeping in mind the need to rely on coal as part of 
our future energy mix, what do you think are appropriate emissions 
targets in what amount of time, such that we challenge industry without 
being unrealistic based on what is technologically possible?
    Answer. The Coal Utilization Research Council (CURC) has a twenty 
year roadmap with emissions targets for intermediary time periods. We 
feel that this is a challenging and realistic set of goals with the 
support of all parties, government and private industry.