[Senate Hearing 110-174]
[From the U.S. Government Printing Office]
S. Hrg. 110-174
CLEAN COAL TECHNOLOGY
ENERGY AND NATURAL RESOURCES
UNITED STATES SENATE
ONE HUNDRED TENTH CONGRESS
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
Printed for the use of the
Committee on Energy and Natural Resources
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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
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
Responses to additional questions................................ 83
CLEAN COAL TECHNOLOGY
WEDNESDAY, AUGUST 1, 2007
Committee on Energy and Natural Resources,
The committee met, pursuant to notice, at 9:28 a.m. in room
SD-366, Dirksen Senate Office Building, Hon. Jeff Bingaman,
OPENING STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM NEW
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
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
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
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,
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
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
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
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
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
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
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
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
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
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.
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.
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.
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.
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
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 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;
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 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.
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
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
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
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
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
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
Mr. Hollinden. Good morning, Mr. Chairman. My name is Jerry
Hollinden and today I'm testifying on behalf of the National
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
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
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
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
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
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
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
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
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
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
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
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,
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
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
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
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,
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.
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
Toward this end, four major technology efforts related to
CO2 emissions reduction from coal-based power systems must
1. Increased efficiency and reliability of integrated
gasification combined cycle (IGCC) power plants.
2. Increased thermodynamic efficiency of pulverized-coal (PC)
3. Improved technologies for capture of CO2 from
coal combustion-and gasification-based power plants.
4. Reliable, acceptable technologies for long-term storage of
Identification of mechanisms to share RD&D financial and technical
risks and to address legal and regulatory uncertainties must take place
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,
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
sootblower optimization via ``intelligent'' sootblower
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
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
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
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
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
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
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
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
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:
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
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.
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
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.
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.
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
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%
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
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
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
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
Senator Craig. I was going to say, I was not here first,
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
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
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
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
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
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
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
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.
STATEMENT OF HON. KEN SALAZAR, U.S. SENATOR
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
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
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
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
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
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
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.
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
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
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,
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
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
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
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
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.
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
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
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
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. 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.
STATEMENT OF HON. LARRY E. CRAIG, U.S. SENATOR
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.
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.
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.
Senator Craig. Anyway, having said that, you talk about the
legal challenges, the good news, the bad news, and the bad
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
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
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
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
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
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
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
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
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
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.
STATEMENT OF HON. JEFF SESSIONS, U.S. SENATOR
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
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
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
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
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
Senator Tester. Thank you, Mr. Chairman.
So that means your answer is going to have to be very
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
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.
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
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
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
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,
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
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
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
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
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
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
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
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
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
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
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
[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/
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
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.
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
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,
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
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
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
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,
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
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
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
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
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
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
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
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
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
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
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
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
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.
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.
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
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
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
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
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.
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-
* 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
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
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
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
Our customers will pay for our decisions, and when they
turn on the switch, they expect the lights to come on at a
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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.
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
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
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
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
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
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
Senator Tester. OK.
Mr. Langley [continuing]. To use oxy-coal, over a plant
Senator Tester. OK. Is there additional water needs with
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
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
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
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
Senator Domenici. OK. What is the response as you gather,
of the companies to that kind of out-year assurance of
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
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
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
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.
STATEMENT OF HON. BOB CORKER, U.S. SENATOR
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
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
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
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.
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
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
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
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
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
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
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. 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
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.
[Whereupon, at 12:28 p.m., the hearing was adjourned.]
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
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
Question 1b. What's FirstEnergy's incentive to take on the
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
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
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
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
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
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
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
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
Again, Great Pont would welcome the opportunity to help the
Committee design a program satisfactory to the Committee in all
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
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
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
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
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
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
2. More stringent energy-efficiency mandates.
3. Policies to encourage efficiency improvements at existing
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
(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''
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
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
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
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
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
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
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-
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.