Clean Coal [1 ed.] 9781613242216, 9781607413585

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RENEWABLE ENERGY: RESEARCH, DEVELOPMENTAND POLICIES SERIES

Copyright © 2009. Nova Science Publishers, Incorporated. All rights reserved.

CLEAN COAL

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RENEWABLE ENERGY: RESEARCH, DEVELOPMENT AND POLICIES SERIES Renewable Fuel Standard Issues Daniel T. Crowe (Editor) 2009. ISBN: 978-1-60692-289-7 Ethanol and Biofuels: Production, Standards and Potential Wesley P. Leland (Editor) 2009. ISBN: 978-1-60692-224-8 Ethanol and Biofuels: Production, Standards and Potential Wesley P. Leland (Editor) 2009 ISBN: 978-1-60876-592-8 (Online Book) Wind Power: Technology, Economics and Policies Cedrick N. Osphey (Editor) 2009. ISBN :978-1-60692-323-8

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Solar Collectors: Energy Conservation, Design and Applications Arthur V. Killian (Editor) 2009. ISBN: 978-1-60741-069-0 Solar Collectors: Energy Conservation, Design and Applications Arthur V. Killian (Editor) 2009. ISBN: 978-1-60876-920-9 (Online book) Wind Energy in Electricity Markets with High Wind Penetration Julio Usaola and Edgardo D. Castronuovo 2009. ISBN: 978-1-60741-153-6 Renewable Energy Grid Integration: The Business of Photovoltaics Marco H. Balderas (Editor) 2009. ISBN: 978-1-60741-324-0 Biomass Gasification: Chemistry, Processes and Applications Jean-Pierre Badeau and Albrecht Levi (Editors) 2009. ISBN: 978-1-60741-461-2 Renewable Energies: Feasibility, Time and Cost Options John O'M. Bockris 2009. ISBN: 978-1-60876-006-0

Clean Energy: An Exporter's Guide to India and China Isaac P. Luttrell (Editors) 2009. ISBN: 978-1-60741-329-5 Physics of Nanostructured Solar Cells Viorel Badescu and Marius Paulescu 2010. ISBN: 978-1-60876-110-4 Clean Coal Editor Klaes G. Douwe (Editor) 2010. ISBN: 978-1-60741-358-5 Rethinking Nuclear Power in the United States Kenneth A. Vellis 2010. ISBN: 978-1-60692-152-4 Biological Barriers to Cellulosic Ethanol Ernest V. Burkheisser 2010. ISBN: 978-1-60692-203-3

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Renewable Energy Grid Integration: Building and Assessment Thomas Georgiadis (Editor) 2010. ISBN: 978-1-60741-326-4

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RENEWABLE ENERGY: RESEARCH, DEVELOPMENTAND POLICIES SERIES

CLEAN COAL

KLAES G. DOUWE

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EDITOR

Nova Science Publishers, Inc. New York

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Independent verification should be sought for any data, advice or recommendations contained in this book. In addition, no responsibility is assumed by the publisher for any injury and/or damage to persons or property arising from any methods, products, instructions, ideas or otherwise contained in this publication. This publication is designed to provide accurate and authoritative information with regard to the subject matter covered herein. It is sold with the clear understanding that the Publisher is not engaged in rendering legal or any other professional services. If legal or any other expert assistance is required, the services of a competent person should be sought. FROM A DECLARATION OF PARTICIPANTS JOINTLY ADOPTED BY A COMMITTEE OF THE AMERICAN BAR ASSOCIATION AND A COMMITTEE OF PUBLISHERS. LIBRARY OF CONGRESS CATALOGING-IN-PUBLICATION DATA Clean coal / editor, Klaes G. Douwe. p. cm. Includes index. ISBN HERRN 1. Clean coal technologies. I. Douwe, Klaes G. TP325.C4865 2009 628.5'32--dc22 2009038382

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CONTENTS

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Preface

ix

Chapter 1

Capturing CO2 from Coal-Fired Power Plants Larry Parker, Peter Folger and Deborah D. Stine

1

Chapter 2

Clean Coal Technology Hearing United States Government Printing Office

Chapter 3

Clean Coal Tech - Power Plant Optimization Klaes G. Douwe

153

Chapter 4

Coal Gasification Hearing - Hawkins Testimony David G. Hawkins

183

Chapter 5

Coal Gasification Hearing - Strakey Testimony Joseph P. Strakey

197

Chapter 6

Potential Exports of U.S. Clean Coal Technology Shannon Fraser and Stefan Osborne

203

33

Chapter Sources

211

Index

213

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PREFACE Coal use today is responsible for large, and mostly avoidable, damages to human health and our water and land. Coal use in the future, along with other fossil fuels, threatens to wreak havoc in the earth's climate system. This book looks at "clean coal" technologies such as coal gasification and carbon capture. Coal gasification, when done in conjunction with carbon capture and storage (CCS) is one technology option that offers our nation an attractive approach to utilize our indigenous fossil energy resources in a more efficient and environmentally sound manner for producing clean, affordable power from coal with dramatically reduced carbon emissions. Coal gasification with CCS can also reduce the carbon impact of using coal to produce ultra-clean fuels for the transportation sector, substitute natural gas (SNG) to heat our homes and fuel our industrial sector, fertilizers to ensure an abundant food supply, and chemicals that play an integral part in our every day lives. Another coal gasification concept explored in this book that could further reduce carbon dioxide (CO2) emission is co-feeding coal and biomass into gasifiers to produce electricity or conventional transportation fuels. In addition to these technologies, this book also describes ways at improving or optimizing the performance of coal-fired power plants, in addition to tools that can be used and are available to cut global warming emissions. This book consists of public domain documents which have been located, gathered, combined, reformatted, and enhanced with a subject index, selectively edited and bound to provide easy access. Chapter 1 - Any comprehensive approach to substantially reduce greenhouse gases must address the world‘s dependency on coal for a quarter of its energy demand, including almost half of its electricity demand. To maintain coal in the world‘s energy mix in a carbonconstrained future would require development of a technology to capture and store its carbon dioxide emissions. This situation suggests to some that any greenhouse gas reduction program be delayed until such carbon capture technology has been demonstrated. However, technological innovation and the demands of a carbon control regime are interlinked; a technology policy is no substitute for environmental policy and must be developed in concert with it. Much of the debate about developing and commercializing carbon capture technology has focused on the role of research, development, and deployment (technology-push mechanisms). However, for technology to be fully commercialized, it must also meet a market demand — a demand created either through a price mechanism or a regulatory requirement (demand-pull mechanisms). Any conceivable carbon capture technology for

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x

Klaes G. Douwe

coal-fired powerplants will increase the cost of electricity generation from affected plants because of efficiency losses. Therefore, few companies are likely to install such technology until they are required to, either by regulation or by a carbon price. Regulated industries may find their regulators reluctant to accept the risks and cost of installing technology that is not required. The Department of Energy (DOE) has invested millions of dollars since 1997 in carbon capture technology research and development (R&D), and the question remains whether it has been too much, too little, or about the right amount. In addition to appropriating funds each year for the DOE program, Congress supported R&D investment through provisions for loan guarantees and tax credits. Congress also authorized a significant expansion of carbon capture and sequestration (CCS) spending at DOE in the Energy Independence and Security Act of 2007. Legislation has also been introduced in the 110th Congress that would authorize spending for carbon capture technology development. Other legislation introduced invokes the symbolism of the Manhattan Project of the 1940s and the Apollo program of the 1960s to frame proposals for large-scale energy policy initiatives that include developing CCS technology. However, commercialization of technology and integration of technology into the private market were not goals of either the Manhattan Project or Apollo program. Finally, it should be noted that the status quo for coal with respect to climate change legislation isn‘t necessarily the same as ―business as usual.‖ The financial markets and regulatory authorities appear to be hedging their bets on the outcomes of any federal legislation with respect to greenhouse gas reductions, and becoming increasingly unwilling to accept the risk of a coal-fired power plant with or without carbon capture capacity. The lack of a regulatory scheme presents numerous risks to any research and development effort designed to develop carbon capture technology. Ultimately, it also presents a risk to the future of coal. Chapter 2 - This chapter is edited and excerpted hearing before the Unites States Senate Committee on Energy and Natural Resources on August 1, 2007. Chapter 3 - The Clean Coal Technology Demonstration Program (CCTDP) and the two following programs—the Power Plant Improvement Initiative (PPII) and the Clean Coal Power Initiative (CCPI)—are government and industry co-funded programs. The goal of these programs is to demonstrate a new generation of innovative coal-utilization technologies in a series of projects carried out across the country. These demonstrations are conducted on a commercial scale to prove the technical feasibility of the technologies and to provide technical and financial information for future applications. A further goal of these programs is to furnish the marketplace with a number of advanced, more efficient coal-based technologies that meet increasingly strict environmental standards. These technologies will help mitigate the economic and environmental barriers that limit the full utilization of coal. To achieve these goals, beginning in 1985 a multi-phased effort has been administered by the U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL). The CCTDP, the earliest program, initiated five separate solicitations. The next program, the PPII, sent out one solicitation, and the CCPI has had two solicitations to date. The projects selected through these solicitations have demonstrated technology options with the potential to meet the needs of the energy markets while satisfying relevant environmental requirements.

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Preface

xi

This report describes four projects aimed at improving or optimizing the performance of coal-fired power plants. All four projects are being conducted under the CCPI and PPII programs. The first project deals with upgrading high moisture lignite by partial drying to enhance its quality and improve overall plant performance. The remaining three projects involve the development of software that optimizes overall power plant performance or some aspect of performance by incorporating features of artificial intelligence (AI), a decisionmaking capability that simulates the human brain. Chapter 4 - This chapter is edited and excerpted testimony by David G. Hawkins before the United States Senate Subcommittee on Science, Technology, and Innovation, Committee on Commerce, Science, and Transportation on April 9, 2008. Chapter 5 - This chapter is edited and excerpted testimony by Joseph P. Strakey before the United States Senate Subcommittee on Science, Technology, and Innovation, Committee on Commerce, Science, and Transportation on April 9, 2008. Chapter 6 - The United States is a world leader in technology that allows coal to be burned for electricity production without excessive emissions of sulfur dioxide, nitrogen oxide, mercury, and particulate matter. To reduce overall emissions, the U.S. coal industry is developing specific technology that can be incorporated into coal-fired power plants. That technology will allow coal to be burned with lower emissions of carbon dioxide.The U.S. technological preeminence in this field presents san opportunity to export the equipment and to license the technology to countries such as China and India,where coal-fired electricity production is rising quickly. This paper estimates the potential for U.S.exports of existing clean coal technology (CCT) to a growing worldwide market. U.S. exports of CCT to Australia,Brazil, China, India, Mexico, New Zealand, South Africa, South Korea, and the European Union (EU)251 could amount to US$36 billion between now and 2030. The potential CCT exports are estimated using several assumptions about future demand for U.S.CCT in those countries.The first assumption is that all new coal-fired electricitygeneration capacity will incorporate CCT. A total estimated demand for CCT is derived by using the projections of the Energy Information Administration (EIA) for increased coal-fired electricity-generating capacity, combined with an estimate of the value of CCT equipment needed for one gigawatt of capacity. If all required CCT equipment were imported and if the United States maintained its current share of each country‘s current CCT imports,the projected demand for U.S. CCT equipment in those countries from 2003 to 2030 would be $36 billion. Specifically, China, India, and South Korea present the greatest value of U.S. CCT exports in this study, representing approximately $26 billion, $3.5 billion, and $3.2 billion, respectively. Australia, Brazil, Mexico, New Zealand, South Africa, and the EU 25 account for an additional $2.9 billion of growth.

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In: Clean Coal Editor: Klaes G. Douwe

ISBN: 978-1-60741-358-5 © 2010 Nova Science Publishers, Inc.

Chapter 1

CAPTURING CO2 FROM COAL-FIRED POWER PLANTS Larry Parker, Peter Folger and Deborah D. Stine

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SUMMARY Any comprehensive approach to substantially reduce greenhouse gases must address the world‘s dependency on coal for a quarter of its energy demand, including almost half of its electricity demand. To maintain coal in the world‘s energy mix in a carbon-constrained future would require development of a technology to capture and store its carbon dioxide emissions. This situation suggests to some that any greenhouse gas reduction program be delayed until such carbon capture technology has been demonstrated. However, technological innovation and the demands of a carbon control regime are interlinked; a technology policy is no substitute for environmental policy and must be developed in concert with it. Much of the debate about developing and commercializing carbon capture technology has focused on the role of research, development, and deployment (technology-push mechanisms). However, for technology to be fully commercialized, it must also meet a market demand — a demand created either through a price mechanism or a regulatory requirement (demand-pull mechanisms). Any conceivable carbon capture technology for coal-fired powerplants will increase the cost of electricity generation from affected plants because of efficiency losses. Therefore, few companies are likely to install such technology until they are required to, either by regulation or by a carbon price. Regulated industries may find their regulators reluctant to accept the risks and cost of installing technology that is not required. The Department of Energy (DOE) has invested millions of dollars since 1997 in carbon capture technology research and development (R&D), and the question remains whether it has been too much, too little, or about the right amount. In addition to appropriating funds each year for the DOE program, Congress supported R&D investment through provisions for loan guarantees and tax credits. Congress also authorized a significant expansion of carbon

2

Larry Parker, Peter Folger and Deborah D. Stine

capture and sequestration (CCS) spending at DOE in the Energy Independence and Security Act of 2007. Legislation has also been introduced in the 110th Congress that would authorize spending for carbon capture technology development. Other legislation introduced invokes the symbolism of the Manhattan Project of the 1940s and the Apollo program of the 1960s to frame proposals for large-scale energy policy initiatives that include developing CCS technology. However, commercialization of technology and integration of technology into the private market were not goals of either the Manhattan Project or Apollo program. Finally, it should be noted that the status quo for coal with respect to climate change legislation isn‘t necessarily the same as ―business as usual.‖ The financial markets and regulatory authorities appear to be hedging their bets on the outcomes of any federal legislation with respect to greenhouse gas reductions, and becoming increasingly unwilling to accept the risk of a coal-fired power plant with or without carbon capture capacity. The lack of a regulatory scheme presents numerous risks to any research and development effort designed to develop carbon capture technology. Ultimately, it also presents a risk to the future of coal.

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INTRODUCTION: COAL AND GREENHOUSE GAS EMISSIONS The world meets 25% of its primary energy demand with coal, a number projected to increase steadily over the next 25 years. Overall, coal is responsible for about 20% of global greenhouse gas emissions.1 With respect to carbon dioxide (CO2), the most prevalent greenhouse gas, coal combustion was responsible for 41% of the world‘s CO2 emissions in 2005 (11 billion metric tons).2 Coal is particularly important for electricity supply. In 2005, coal was responsible for about 46% of the world‘s power generation, including 50% of the electricity generated in the United States, 89% of the electricity generated in China, and 81% of the electricity generated in India.3 Coal-fired power generation is estimated to increase 2.3% annually through 2030, with resulting CO2 emissions estimated to increase from 7.9 billion metric tons per year to 13.9 billion metric tons per year. For example, during 2006, it is estimated that China added over 90 gigawatts (GW) of new coal-fired generating capacity, potentially adding an additional 500 million metric tons of CO2 to the atmosphere annually.4 Table 1. Expected Costs of CCS Technology Elements CCS Element $/Metric Ton of CO2 Capture $40-$80 Storage $3-$8 Monitoring and Verification $0.2-$1.0 Source: S. Julio Friedmann, Carbon Capture and Sequestration As a Major Greenhouse Gas Abatement Option (November 2007), p. 11. Note: Capture and storage costs are very site-specific. These estimates reflect the magnitude of difference between capture and storage costs; actual site-specific costs could vary substantially from these estimates. Estimates do not include any transportation costs.

Capturing CO2 from Coal-Fired Power Plants

3

Developing a means to control coal-derived greenhouse gas emissions is an imperative if serious reductions in worldwide emissions are to occur in the foreseeable future. Developing technology to accomplish this task in an environmentally, economically, and operationally acceptable manner has been an ongoing interest of the federal government and energy companies for a decade, but no commercial device to capture and store these emissions is currently available for large-scale coal-fired power plants. Arguably the most economic and technologically challenging part of the carbon capture and sequestration (CCS) equation is capturing the carbon and preparing it for transport and storage.5 Depending on site-specific conditions, the capture component of a CCS system can be the dominant cost-variable, and the component that could be improved most dramatically by further technological advancement. As indicated in Table 1, capture costs could be 5-10 times the cost of storage. Breakthrough technologies that substantiallyreduce the cost of capturing CO2 from existing or new power plants, for example by 50% or more, would immediately reshape the economics of CCS. Moreover, technological breakthroughs would change the economics of CCS irrespective of a regulatory framework that emerges and governs how CO2 is transported away from the power plant and sequestered underground. In contrast, the cost of transporting CO2 and sequestering it underground is likely less dependent on technological breakthroughs than on other factors, such as:

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the costs of construction materials and labor (in the case of pipelines for CO2 transport); the degree of geologic characterization required to permit sequestration; the requirements for measuring, monitoring, and verifying permanent CO2 storage; the costs of acquiring surface and subsurface rights to store CO2; costs of insurance and long-term liability; and other variables driving the cost of transportation and sequestration.6 That is not to say that the transportation and storage components of CCS are independent of cost and timing. Depending on the degree of public acceptance of a large-scale CCS enterprise, the transportation and sequestration costs could be very large, and it may take years to reach agreement on the regulatory framework that would guide long-term CO2 sequestration. But the variables driving cost and timing for the transportation and storage of CO2 are less amenable to technological solution. This report examines the current effort to develop technology that would capture CO2. First, the paper outlines the current status of carbon capture technology. Second, the paper examines the role of government in developing that technology, both in terms of creating a market for carbon capture technology and encouraging development of the technology. Finally, the paper concludes with a discussion of implications of capture technology for climate change legislation.

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Larry Parker, Peter Folger and Deborah D. Stine

BACKGROUND: WHAT IS CARBON CAPTURE TECHNOLOGY AND WHAT IS ITS STATUS? Major reductions in coal-fired CO2 emissions would require either pre-combustion, combustion modification, or post-combustion devices to capture the CO2. Because there is currently over 300 GW of coal-fired electric generating capacity in the United States and about 600 GW in China, a retrofittable post-combustion capture device could have a substantial market, depending on the specifics of any climate change program. The following discussion provides a brief summary of technology under development that may be available in the near-term. It is not an exhaustive survey of the technological initiatives currently underway in this area, but illustrative of the range of activity. Funding for current government research and development activities to improve these technologies and move them to commercialization are discussed later.

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Post-Combustion CO2 Capture Post-combustion CO2 capture involves treating the burner exhaust gases immediately before they enter the stack. The advantage of this approach is that it would allow retrofit at existing facilities that can accommodate the necessary capturing hardware and ancillary equipment. In this sense, it is like retrofitting post-combustion sulfur dioxide (SO2), nitrogen oxides (NOx), or particulate control on an existing facility. A simplified illustration of this process is provided in Figure 1. Post-combustion processes capture the CO2 from the exhaust gas through the use of distillation, membranes, or absorption (physical or chemical). The most widely-used capture technology is the chemical absorption process using amines (typically monoethanolamine (MEA)) available for industrial applications. Pilot-plant research on using ammonia (also an amine) as the chemical solvent is currently underway with demonstration plants announced. These approaches to carbon capture are discussed below. Numerous other solvent-based postcombustion processes are in the bench-scale stage.7

Source: Scottish Centre for Carbon Storage. Figure available at [http://www.geos.ed.ac.uk/ sccs/capture/postcombustion.html]. Figure 1. Simplified Illustration of Post-Combustion CO2 Capture

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Capturing CO2 from Coal-Fired Power Plants

5

Monoethanolamine (MEA) The MEA CO2 carbon capture process is the most proven and tested capture process available. The basic design (common to most solvent-based processes) involves passing the exhaust gases through an absorber where the MEA interacts with the CO2 and absorbs it. The now CO2-rich MEA is then pumped to a stripper (also called a regenerator) which uses steam to separate the CO2 from the MEA. Water is removed from the resulting CO2, which is compressed while the regenerated MEA is purged of any contaminants (such as ammonium sulfate) and recirculated back to the absorber. The process can be optimized to remove 9095% of the CO2 from the flue gas.8 Although proven on an industrial scale, it has not been applied to the typically larger volumes of flue gas streams created by coal-fired powerplants. The technology has three main drawbacks that would make current use on a coal-fired powerplant quite costly. First is the need to divert steam away from its primary use — generating electricity — to be used instead for stripping CO2 from MEA. A second related problem is the energy required to compress the CO2 after it‘s captured — needed for transport through pipelines — which lowers overall powerplant efficiency and increases generating costs. A recent study by the Massachusetts Institute of Technology (MIT) estimated the efficiencylosses from the installation of MEA from 25%-28% for new construction and 36%-42% for retrofit on an existing plant.9 This loss of efficiency comes in addition to the necessary capital and operations and maintenance cost of the equipment and reagents. For new construction, the increase in electricity generating cost on a levelized basis would be 60%-70%, depending on the boiler technology.10 In the case of retrofit plants where the capital costs were fully amortized, the MEA capture process would increase generating costs on a levelized basis by about 220%-250%.11 A third drawback is degradation of the amine through either overheating (over 205 degrees Fahrenheit [F]) in the absorber or through oxidation from oxygen introduced in the wash water, chemical slurry, or flue gas that reacts with the MEA. For example, residual SO2 in the flue gas will react with the MEA to form ammonium sulfate that must be purged from the system.12 This could be a serious problem for existing plants that do not have highly efficient flue gas desulfurization (FGD) or selective catalytic reduction (SCR) devices (or none), requiring either upgrading of existing FGD and SCR equipment, or installation of them in addition to the MEA process. Chilled Ammonia (Alstom) An approach to mitigating the oxidation problem identified above is to use an ammoniabased solvent rather than MEA. Ammonia is an amine that absorbs CO2 at a slower rate than MEA. In a chilled ammonia process, the flue gas temperature is reduced from about 130 degrees F to about 35-60 degrees F. This lower temperature has two benefits: (1) it condenses the residual water in the flue gas, which minimizes the volume of flue gas entering the absorber; and (2) it causes pollutants in the flue gas, such as SO2, to drop out, reducing the need for substantial upgrading of upstream control devices.13 Using a slurry of ammonium carbonate and ammonium bicarbonate, the solvent absorbs more than 90% of the CO2 in the flue gas. The resulting CO2-rich ammonia is regenerated and the CO2 is stripped from the ammonia mixture under pressure (300 pounds per square inch [psi] compared with 15 psi using MEA), reducing the energy necessary to compress the CO2 for transportation (generally around 1,500 psi).14

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The chilled ammonia process is a proprietary process, owned by Alstom. In collaboration with American Electric Power (AEP) and RWE AG (the largest electricity producer in Germany), Alstom has announced plans to demonstrate the technology on a 20 megawatt (MW) slipstream15 at AEP‘s Mountaineer plant in West Virginia, and to inject the captured CO2 into deep saline formations on site.16 Once commercial viability is demonstrated at Mountaineer, AEP plans to install the technology at its 450 MW Northeastern Station in Oologah, OK, early in the next decade. The captured gas is to be used for Enhanced Oil Recovery (EOR). The target is for full commercialization in 2015.

Ammonia (Powerspan) A second ammonia-based, regenerative process for CO2 capture from existing coal-fired facilities does not involve chilling the flue gas before it enters the absorber. Using higher flue gas temperatures increases the CO2 absorption rate in the absorber and, therefore, the CO2 removal. However, the higher flue gas temperatures also mean that upgrades to existing FGD devices would be necessary.17 This process is being developed by Powerspan.18 Called ECO2, two commercial demonstrations designed for 90% CO2 capture have been announced with projected operations to begin in 2011 and 2012. The first will use a 120 MW slipstream from Basin Electric‘s Antelope Valley Station in North Dakota. The second will be sited at NRG‘s W.A. Parish plant in Texas and use a 125 MW slipstream. The captured CO2 is to be sold or used for EOR.

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Pre-combustion CO2 Capture Currently, a requirement for the pre-combustion capture of CO2 is the use of Integrated Gasification Combined-cycle (IGCC) technology to generate electricity.19 There are currently four commercial IGCC plants worldwide (two in the United States) each with a capacity of about 250 MW. The technology has yet to make a major breakthrough in the U.S. market because its potential superior environmental performance is currently not required under the Clean Air Act, and, thus, as discussed above for carbon capture technology, its higher costs can not be justified (see the Virginia State Corporation Commission decision, discussed below). Carbon capture in an IGCC facility would happen before combustion, under pressure usinga physical solvent (e.g., Selexol and Rectisol processes), or a chemical solvent (e.g., methyl diethanolaimine (MDEA)). A simplified illustration of this process is provided in Figure 2. Basically, the IGCC unit pumps oxygen and a coal slurry into a gasifier to create a syngas consisting of carbon monoxide and hydrogen. The syngas is cleaned of conventional pollutants (SO2, particulates) and sent to a shift reactor which uses steam and a catalyst to produce CO2 and hydrogen. Because the gases are under substantial pressure with a high CO2 content, a physical solvent can separate out the CO2. The advantage of a physical solvent is that the CO2 can be freed and the solvent regenerated by reducingthe pressure — a process that is substantially less energy-intensive than having to heat the gas as in an MEA stripper.

Capturing CO2 from Coal-Fired Power Plants

7

Source: Scottish Centre for Carbon Storage. Figure available at [http://www.geos.ed.ac.uk/ sccs/capture/precombustion.html]. Figure 2. Simplified Illustration of Pre-Combustion CO2 Capture

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From the capture process, the CO2 is further compressed for transportation or storage, and the hydrogen is directed through gas and steam cycles to produce electricity. MIT estimates the efficiency loss from incorporating capture technology on an IGCC facility is about 19% (from 38.4% efficiency to 31.2%).20 This loss of efficiency comes in addition to thenecessary capital and operations and maintenance cost of the equipment and reagents. For new construction, the estimated increase in electricity generating cost on a levelized basis generally ranges from 22%-25%, with American Electric Power estimating the cost increase at 41%.21 There is a lot of activity surrounding the further commercialization of IGCC technology and in the demonstration of carbon capture methods on that technology. As illustrated in Figure 3, numerous projects are currently in the development pipeline. Whether development will be delayed by DOE‘s decision to restructure the FutureGen initiative (as discussed later, see box) is unclear.22

Combustion CO2 Capture Attempts to address CO2 during the combustion stage of generation focus on increasing the CO2 concentration of the flue gas exiting the boiler. The more concentrated the CO2 is when it exits the boiler, the less energy (and cost) is required later to prepare it for transport or storage. The most developed approach involves combusting the coal with nearly pureoxygen(>95%) instead of air, resulting in a flue gas consisting mainly of highly concentrated CO2 and water vapor. Using existing technology, the oxygen would be provided by an air-separation unit — an energy intensive process that would be the primary source of reduced efficiency. The details of this ―oxy-fuel‖ process are still being refined, but generally, from the boiler the exhaust gas is cleaned of conventional pollutants (SO2, NOx, and particulates) and some of the gases recycled to the boiler to control the higher temperature resulting from coal combustion with pure oxygen. The rest of the gas stream is sent for further purification and compression in preparation for transport and/or storage.23 Depending on site-specific conditions, oxy-fuel could be retrofitted onto existing boilers. A simplified illustration of this process is provided in Figure 4.

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Larry Parker, Peter Folger and Deborah D. Stine

Source: Emerging Energy Research (EER), ―Global IGCC Power Markets and Strategies: 2007-2030‖ (December 2007). See [http://www.emerging-energy.com/].

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Figure 3. Status of Global IGCC Projects

Source: Scottish Centre for Carbon Storage. Figure available at [http://www.geos.ed.ac.uk/ sccs/capture/oxyfuel.html]. Figure 4. Simplified Illustration of Oxy-fuels CO2 Capture

The largest oxy-fuel demonstration projects under development are the Vattenfall Project in Germany and the Callide Oxyfuel Project in Queensland, Australia. The Vattenfall project is a 30MW pilot plant being constructed at Schewarze Pumpe and scheduled to begin operation soon. The captured CO2 will be put in geological storage once siting and permitting processes are completed.24 The Callide Project is being sponsored by CS Energy, who, with six partners, is retrofitting a 30 MW boiler at its Callide-A power station with an oxy-fuel process. Operation of the oxy-fuel process is scheduled for 2010, with transport and geological storage of the CO2 planned for 2011.25 Numerous other bench- and pilot-plant scale initiatives are underway with specific work being conducted on improving the efficiency of the air-separation process. MIT estimates the

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efficiency losses from the installation of oxy-fuel at 23% for new construction and 31%-40% for retrofit on an existing plant (depending on boiler technology).26 This loss of efficiency comes in addition to the necessary capital and operations and maintenance cost of the equipment and reagents. For new construction, the increase in electricity generating cost on a levelized basis would be about 46%. In the case of retrofit plants where the capital costs are fully amortized, the oxy-fuel capture process would increase generating costs on a levelized basis by about 170%-206%.27

DOE-Supported Technology Development

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As summarized in Table 2, CO2 capture technology is currently estimated to significantly increase the costs of electric generation from coal-fired power plants. Research is ongoing to improve the economics and operation of carbon capture technology. DOE‘s National Energy Technology Laboratory (NETL) is supporting a variety of carbon capture technology research and development (R&D) projects for pre-combustion, oxy-combustion, and post-combustion applications. A detailed description of all the NETL projects, and of carbon capture technology R&D efforts in the private sector, is beyond the scope of this report. However, funding from DOE (described later) is supporting approximately two dozen carbon capture research projects that range from bench-scale to pilot-scale testing.28 The types of research explored in the NETL-supported projects include the use of membranes, physical solvents, oxy-combustion, chemical sorbents, and combinations of chemical and physical solvents. According to the NETL, these technologies will be ready for slipstream tests by 2014 and for large-scale field testing by 2018.29 Projects pursued by the private sector may be ready for pilot-scale testing by 2010 and possibly sooner.30

ROLES FOR GOVERNMENT Generally, studies that indicate that emerging, less carbon-intensive new technologies are both available and cost-effective incorporate a price mechanism (such as a carbon tax) that provides the necessary long-term price signal to direct research, development, demonstration, and deployment efforts (called ―demand-pull‖ or ―market-pull‖ mechanisms).31 Developing such a price signal involves variables such as the magnitude and nature of the market signal, and its timing, direction, and duration. In addition, studies indicate combining a sustained price signal with public support for research and development efforts is the most effective long-term strategy for encouraging development of new technology (called ―technologypush‖ mechanisms).32 As stated by Richard D. Morgenstern: ―The key to a long term research and development strategy is both a rising carbon price, and some form of government supported research program to compensate for market imperfections.‖33 The various roles the government could take in encouraging development of environmental technologies are illustrated in Figure 5. The federal role in the innovation process is a complex one, reflecting the complexity of the innovation process itself. The inventive activity reflected by government and private research and development efforts overlap with demand pull mechanisms to promote or require adoption of technology, shaping

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the efforts. Likewise, these initiatives are facilitated by the government as a forum for feedback gained through both developed and demonstration efforts and practical application. The process is interlinked, overlapping, and dynamic, rather than linear. Attempting to implement one role in a vacuum can result in mis-directed funding or mis-timing of results. This section discusses these different roles with respect to encouraging development of carbon capture technology, including (1) the need for a demand-pull mechanism and possible options; (2) current technology-push efforts at the U.S. Department of Energy (DOE) and the questions they raise; and (3) comparison of current energy research and development efforts with past mission-oriented efforts. Table 2. MIT Estimates of Additional Costs of Selected Carbon Capture Technology (Percent Increase in Electric Generating Costs on Levelized Basis)

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New Construction Retrofit* Post-combustion (MEA) 60%-70% 220%-250% Pre-combustion (IGCC) 22%-25% not applicable Combustion (Oxy-fuel) 46% 170%-206% Source: Massachusetts Institute of Technology, The Future of Coal: An Interdisciplinary MIT Study (2007), pp.27, 30, 36, 149. See text for discussion of technologies. * Assumes capital costs have been fully amortized.

Source: Margaret R. Taylor, Edward S. Rubin and David A Hounshell, ―Control of SO 2 Emissions from Power Plants: A Case of Induced Technological Innovation in the U.S.,‖ Technological Forecasting & Social Change (July 2005), p. 699. Figure 5. The Federal Role in R&D

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THE NEED FOR A DEMAND-PULL MECHANISM Economists note that the driving force behind the development of new and improved technologies is the profit motive.... However, market forces will provide insufficient incentives to develop climate-friendly technologies if the market prices of energy inputs do not fully reflect their social cost (inclusive of environmental consequences).... Even if energy prices reflect all production costs, without an explicit greenhouse gas policy firms have no incentive to reduce their greenhouse gas emissions per se beyond the motivation to economize on energy costs. For example, a utility would happily find a way to generate the same amount of electricity with less fuel, but without a policy that makes carbon dioxide emissions costly, it would not care specifically about the carbon content of its fuel mix in choosing between, say, coal and natural gas. For firms to have the desire to innovate cheaper and better ways to reduce emissions (and not merely inputs), they must bear additional financial costs for emissions.34

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Much of the focus of debate on developing carbon capture technology has been on research, development, and demonstration (RD&D) needs. However, for technology to be fully commercialized, it must meet a market demand — a demand created either through a price mechanism or a regulatory requirement. As suggested by the previous discussion, any carbon capture technology for coal-fired powerplants will increase the cost of electricity generation from affected plants with no increase in efficiency. Therefore, widespread commercialization of such technology is unlikely until it is required, either by regulation or by a carbon price. Indeed, regulated industries may find their regulators reluctant to accept the risks and cost of installing technology that is not required by legislation. This sentiment was reflected in a recent decision by the Virginia State Corporation Commission in denying an application by Appalachian Power Company (APCo) for a rate adjustment to construct an IGCC facility: The Company asserted that the value of this project is directly related to (1) potential future legal requirements for carbon capture and sequestration; and (2) the proposed IGCC Plant‘s potential ability to comply cost effectively with any such requirements. Both of these factors, however, are unknown at this time and do not overcome the other infirmities in the Application. The legal necessity of, and the capability of, cost-effective carbon capture and sequestration in this particular IGCC Plant, at this time, has not been sufficiently established to render APCo‘s Application reasonable or prudent under the Virginia Statute we must follow.35

At the same time there is reluctance to invest in technology that is not required, the unresolved nature of greenhouse gas regulation is affecting investment in any coal-fired generation.36 The risk involved in investing in coal-fired generation absent anticipated greenhouse gas regulations is outlined in ―The Carbon Principles‖ announced by three Wall Street banks — Citi, JP Morgan Chase, and Morgan Stanley — in February 2008. As stated in their paper: The absence of comprehensive federal action on climate change creates unknown financial risks for those building and financing new fossil fuel generation resources. The Financial Institutions that have signed the Principles recognize that federal CO 2 control

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legislation is being considered and is likely to be adopted during the service life of many new power plants. It is prudent to take concrete actions today that help developers, investors and financiers to identify, analyze, reduce and mitigate climate risks. 37

Similarly, lack of a regulatory scheme presents numerous risks to any RD&D effort designed to develop carbon capture technology. Unlike a mission-oriented research effort, like the Manhattan Project to develop an atomic bomb, where the ultimate goal is victory and the cost virtually irrelevant, research efforts focused on developing a commercial device need to know what the market wants in a product and how much the product is worth. At the current time, the market value of a carbon capture device is zero in much of the country because there is no market for carbon emissions or regulations requiring their reduction.38 All estimates of valueare hypothetical — dependent on a reduction program or regulatory regime that doesn‘t exist. With no market or regulatory signals determining appropriate performance standards and cost-effectiveness criteria, investment in carbon capture technology is a risky business that could easily result in the development of a ―white elephant‖ or ―gold-plated‖ technology that doesn‘t meet market demand. While the ―threat‖ of a carbon regime is stimulating RD&D efforts and influencing decisions about future energy (particularly electricity) supply, the current spread of greenhouse gas control regimes being proposed doesn‘t provide much guidance in suggesting appropriate performance and cost-effectiveness benchmarks for a solution with respect to coal-fired generation. For example, isolating just one variable in the future price of carbon under a cap-and-trade program — tonnage reduction requirement — the future value of carbon reductions can vary substantially.39 As illustrated by Figure 6, three possible reduction targets in 2050 — maintaining current 2008 levels (287 billion metric tons [bmt]), reducing emissions to 50% of 1990 levels (203 bmt), and reducing emissions to 20% of 1990 levels (167 bmt) — result in substantially different price tracks for CO2.40 Without a firm idea of the tonnage goal and reduction schedule, any deployment or commercialization strategy would be a high-risk venture, as suggested by the previously noted Virginia State Corporation Commission conclusion.

CO2e = carbon dioxide equivalent Source: Segey Paltsev, et al., Assessment of U.S. Cap-and-Trade Proposals, MIT Joint Program on the Science and Policy of Global Change, Report 146 (April 2007), p. 16. For details on the analysis presented here, consult the report. Available at [http://mit.edu/globalchange]. Figure 6. CO2 Price Projections

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APPROACHES TO A DEMAND-PULL MECHANISM There are two basic approaches to a demand-pull mechanism: (1) a regulatory requirement, and (2) a price signal via a market-based CO2 reduction program. These approaches are not mutually exclusive and can serve different goals. For example, a regulation focused on new construction (such as the New Source Performance Standard under Section 111 of the Clean Air Act41) could be used to phase in deployment of carbon capture technology and prevent more coal-fired facilities from being constructed without carbon capture (or ensure they would be at least ―ready‖ for carbon capture later). At the same time, a carbon tax or cap-and-trade program could be initiated to begin sending a market signal to companies that further controls will be necessary in the future if they decide to continue operating coal-fired facilities.

Creating Demand Through a Regulatory Requirement: An Example from the SO2 New Source Performance Standards

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It is an understatement to say that the new source performance standards promulgated by the EPA were technology-forcing. Electric utilities went from having no scrubbers on their generating units to incorporating very complex chemical processes. Chemical plants and refineries had scrubbing systems that were a few feet in diameter, but not the 30- to 40-foot diameters required by the utility industry. Utilities had dealt with hot flue gases, but not with saturated flue gases that contained all sorts of contaminants. Industry, and the US EPA, has always looked upon new source performance standards as technology-forcing, because they force the development of new technologies in order to satisfy emissions requirements. 42

The most direct method to encourage adoption of carbon capture technology would be to mandate it. Mandating a performance standard on coal-fired powerplants is not a new idea; indeed, Section 111 of the Clean Air Act requires the Environmental Protection Agency (EPA) to develop New Source Performance Standards (NSPS) for any new and modified powerplant (and other stationary sources) that in the Administrator‘s judgment―causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public heath or welfare.‖ NSPS can be issued for pollutants for which there is no National Ambient Air Quality Standard (NAAQS), like carbon dioxide.43 In addition, NSPS is the floor for other stationary source standards such as Best Available Control Technology (BACT) determinations for Prevention of Significant Deterioration (PSD) areas and Lowest Achievable Emission Rate (LAER) determinations for non-attainment areas.44 The process of forcing the development of emission controls on coal-fired powerplants is illustrated by the 1971 and 1978 SO2 NSPS for coal-fired electric generating plants. The Clean Air Act states that NSPS should reflect ―the degree of emission limitation achievable through the application of the best systemof emission reduction which (taking into account the cost of achieving such reductions and any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.‖45 In promulgating its first utility SO2 NSPS in 1971, EPA determined that a 1.2 pound of SO2 per million Btu of heat input performance standard met the criteria of Sec. 111 — a standard that required, on average, a 70% reduction in new powerplant emissions,

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and could be met by low-sulfur coal that was available in both the eastern and western parts of the United States, or by the use of emerging flue gas desulfurization (FGD) devices.46 At the time the 1971 Utility SO2 NSPS was promulgated, there was only one FGD vendor (Combustion Engineering) and only three commercial FGD units in operation — one of which would be retired by the end of the year.47 This number would increase rapidly, not only because of the NSPS, but also because of the promulgation of the SO2 NAAQS, the 1973 Supreme Court decision preventing significant deterioration of pristine areas,48 and state requirements for stringent SO2 controls, which opened up a market for retrofits of existing coal-fired facilities in addition to the NSPS focus on new facilities. Indeed, most of the growth in FGD installations during the early and mid-1970s was in retrofits — Taylor estimates that between 1973 and 1976, 72% of the FGD market was in retrofits.49 By 1977, there were 14 vendors offering full-scale commercial FGD installation.50 However, despite this growth, only 10% of the new coal-fired facilities constructed between 1973 and 1976 had FGD installations. In addition, the early performance of these devices was not brilliant.51 In 1974, American Electric Power (AEP) spearheaded an ad campaign to have EPA reject FGD devices as ―too unreliable, too impractical for electric utility use‖ in favor of tall stacks, supplementary controls, and low-sulfur western coal.52 This effort was ultimately unsuccessful as the Congress chose to modify the NSPS requirements for coal-fired electric generators in 1977 by adding a ―percentage reduction‖ requirement. As promulgated in 1979, the revised SO2 NSPS retained the 1971 performance standard but added a requirement for a 70%-90% reduction in emissions, depending on the sulfur content of the coal.53 At the time, this requirement could be met only through use of an FGD device. The effect of the ―scrubber requirement‖ is clear from the data provided in Figure 7. Based on their analysis of FGD development, Taylor, Rubin, and Hounshell state the importance of demand-pull instruments: Results indicate that: regulation and the anticipation of regulation stimulate invention; technology-push instruments appear to be less effective at prompting invention than demandpull instruments; and regulatory stringency focuses inventive activity along certain technology pathways.54

Source: Adapted by Taylor from Soud (1994). See Margaret R. Taylor, op. cit., 74. Note: Numbers are archival through June 1994, then projected for 1994-96. Figure 7. Number of FGD Units and Cumulative GWCapacity of FGD Units: 1973-1996

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That government policy could force the development of a technology through creating a market should not suggest that the government was limited to that role, or that the process was smooth or seamless. On the latter point, Shattuck, et al., summarize the early years of FGD development as follows: The Standards of Performance for New Sources are technology-forcing, and for the utility industry they forced the development of a technology that had never been installed on facilities the size of utility plants. That technology had to be developed, and a number of installations completed in a short period of time. The US EPA continued to force technology through the promulgation of successive regulations. The development of the equipment was not an easy process. What may have appeared to be the simple application of an equipment item from one industry to another often turned out to be fraught with unforeseen challenges. 55

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The example indicates that technology-forcing regulations can be effective in pulling technology into the market — even when there remains some operational difficulties for that technology. The difference for carbon capture technology is that for long-term widespread development, a new infrastructure of pipelines and storage sites may be necessary in addition to effective carbon capture technology. In the short-term, suitable alternatives, such as enhanced oil recovery needs and in-situ geologic storage, may be available to support early commercialization projects without the need for an integrated transport and storage system. Likewise, with economics more favorablefor new facilities than for retrofits, concentrating on using new construction to introduce carbon capture technology might be one path to widespread commercialization. As an entry point to carbon capture deployment, a regulatory approachsuchasNSPS mayrepresent a first step, as suggested by the SO2 NSPS example above.

Creating Demand Through a Price Signal: Carbon Taxes, Allowance Pricing, and Auctions Much of the current discussion of developing a market-pull mechanism for new carbon capture technology has focused on creating a price for carbon emissions. The literature suggests that this is an important component for developing new technology, perhaps more important even than research and development. As stated by the Congressional Budget Office (CBO): Analyses that consider the costs and benefits of both carbon pricing and R&D all come to the same qualitative conclusion: near-term pricing of carbon emissions is an element of a costeffective policy approach. That result holds even though studies make different assumptions about the availability of alternative energy technologies, the amount of crowding out caused by federal subsidies, and the form of the policy target (maximizing net benefits versus minimizing the cost of reaching a target).56

Two basic approaches can be employed in the case of a market-based greenhouse gas control program: a carbon tax and a cap-and-trade program. The carbon tax would create a long-term price signal to stimulate innovation and development of new technology. This price

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signal could be strengthened if the carbon tax were escalated over the long run — either by a statutorily determined percentage or by an index (such as the producer price index). A carbon tax‘s basic approach to controlling greenhouse gas emissions is to supply the marketplace with a stable, consistent price signal — a signal that would also inform innovators as to the cost performance targets they should seek in developing alternative technologies. Designed appropriately, there would be little danger of the price spikes or market volatility that can occur in the early stages of a tradeable permit program.57 A cap-and-trade program creates a price signal for new technology through a market price for carbon permits (called allowances) — an allowance is a limited authorization to emit one metric ton of carbon dioxide equivalent (CO2e). In a cap-and-trade system, these allowances are issued by the government and either allocated or auctioned to affected companies who may use them to comply with the cap, sell them to other companies on the market, or bank them for future use or sale. The resulting market transactions result in an allowance price. This price on carbon emissions, however, can be both uncertain and volatile.58 In addition, a low allowance price may be insufficient to encourage technology development and refinement. For example, the 1990 acid rain control program effectively ended the development of FGD for retrofit purposes by setting an emission cap that resulted in low allowance prices and that could be met through the use of low-sulfur coal. Noting that only 10% of phase 1 facilities chose FGD to comply with its requirements, Taylor, et al., state: The 1990 CAAA, however, although initially predicted to increase demand for FGD systems, eroded the market potential for both dry and wet FGD system applications at existing power plants when the SO2 allowance trading market returned low-sulfur coal to its importance in SO2 control.... As a result, research in dry FGD technology declined significantly. In this case, the flexibility provided by the 1990 acid rain regulations discouraged inventive activity in technologies that might have had broader markets under the traditional command-and-control regimes in place prior to 1990.59 [footnotes from original text omitted]

A cap-and-trade program need not have such a result. For example, to more effectively promote carbon capture technology, the price signal under a greenhouse gas reduction program could be strengthened by requiring the periodic auctioning of a substantial portion of available allowances rather than giving them away at no cost. The SO2 program allocated virtually all of its allowance at no cost to affected companies. Auctioning a substantial portion of available allowances could create a powerful price signal and provide incentives for deploying new technology if structured properly.60 The program could create a price floor to facilitate investment in new technology via a reserve price in the allowance auction process. In addition, the stability of that price signal could be strengthened by choosing to auction allowances on a frequent basis, ensuring availability of allowances close to the time of expected demand and making any potential short-squeezing of the secondary market more difficult.61 One positive aspect of the acid rain cap-and-trade experience for encouraging deployment of technology was the effectiveness of ―bonus‖ allowances and deadline extensions as incentives to install FGD. Specifically, about 3.5 million of the allowances were earmarked for Phase 1 powerplants choosing to install 90% control technology (such as

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FGD). Such units were allowed to delay Phase 1 compliance from 1995 to 1997 and receive two allowances for each ton of SO2 reduced below a 1.2 lb. per mmBtu level during 19971999. The 3.5 million allowance reserve was fully subscribed, and was a major factor in what FGD was installed during Phase 1 of the program. This experience may bodewell for proposed CCS ―bonus allowance‖ provisions in several greenhouse gas reduction schemes currently introduced in the Congress.

CURRENT TECHNOLOGY-PUSH MECHANISMS: DOE INVESTMENT IN CCS R&D The Department of Energy (DOE) is currently engaged in a variety of activities to push development and demonstration of carbon capture technologies. These activities include direct spending on research and development, and providing loan guarantees and tax credits to promote carbon capture projects. These technology-push incentives, and the issues they raise, are discussed below.

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Direct Spending on R&D The federal government has recognized the potential need for carbon capture technology — as part of broader efforts to address greenhouse-gas induced climate change — since at least 1997 when the DOE spent approximately $1 million for the entire CCS program.62 DOE spending on the CCS program has increased over the 11-year period to its highest amount in FY2008 of $118.9 million.63 If DOE spending for FutureGen (discussed further below) is included, together with carbon-capture technology investments through theInnovations for Existing Plants (IEP) and the Advanced Integrated Gasification Combined Cycle (AIGCC) programs (also within the DOE Office of Fossil Energy), then CCS spending at DOE could equal nearly $283 million in FY2008.64 If the Administration‘s budget request for FY2009 were fully funded, then overall spending for CCS R&D could equal $414 million, a 46% increase over FY2008 spending levels. Figure 8 shows the trajectory of overall DOE spending on CCS, under this accounting, since FY1997. From FY1997 to FY2007, a total of nearly $500 million has been allocated to CCS at DOE. According to DOE, the CCS line item in its Fossil Energy budget allocated approximately 12% of the FY2008 budget to carbon capture technologyspecifically, or approximately $14.3 million. Nearly $68 million, or 57% of the FY2008 CCS budget, was allocated to the regional partnerships,65 which are primarily pursuing projects to store CO2 underground, not to develop capture technologies. The remaining third of the FY2008 budget was allocated to other aspects of CCS, such as technologies for monitoring, mitigating, and verifying the long-term storage of CO2, other aspects of sequestration, breakthrough concepts (which includes capture technologies), and others. (See Figure 9 for the breakdown of the DOE CCS program spending in FY2008.) Of the $283 million in total funding for CCS in FY2008 (by one estimation, which includes IEP and AIGCC funding (Figure 8)), less than half is likely allocated for developing carbon capture technology.

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Source: Personal communication, Timothy E. Fout, General Engineer, DOE National Energy Technology Laboratory, Morgantown, WV (July 16, 2008); and U.S. Department of Energy, FY2009 Congressional Budget Request, Volume 7, DOE/CF-030 (Washington, D.C., February 2008). Note: Funding for FutureGen shown is the appropriated amounts. AIGCC means Advanced Integrated Gasification Combined Cycle, and IEP means Innovations for Existing Plants; both are programs under DOE‘s Office of Fossil Energy. Funding for FY2009 are the requested amounts.

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Figure 8. Spending on CCS at DOE Since FY1997

Source: Personal communication, Timothy E. Fout, General Engineer, DOE National Energy Technology Laboratory, Morgantown, WV (July 16, 2008). Note: Total expected spending for CCS in FY2008 shown on this chart equals $118.91 million. Also, MMV as shown on the chart stands for measurement, monitoring, and verification. Figure 9. Expected Spending on CCS by Category in FY2008

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Loan Guarantees and Tax Credits

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Appropriations represent one mechanismfor funding carbon capture technology RD&D; others include loan guarantees and tax credits, both of which are available under current law. Loan guarantee incentives that could be applied to CCS are authorized under Title XVII of the Energy Policy Act of 2005 (EPAct2005, P.L. 109-58). Title XVII of EPAct2005 (42 U.S.C. 16511-16514) authorizes the Secretary of Energy to make loan guarantees for projects that, among other purposes, avoid, reduce, or sequester air pollutants or anthropogenic emissions of greenhouse gases. The Consolidated Appropriations Act for FY2008 (P.L. 110161) provides loan guarantees authorized byEPAct2005 for coal-based power generation and industrial gasification activities that incorporate CCS, as well as for advancedcoalgasification. The explanatory statement66 directs allocation of $6 billion in loan guarantees for retrofitted and new facilities that incorporate CCS or other beneficial uses of carbon. Title XIII of EPAct2005 provides for tax credits that can be used for Integrated Gasification Combined Cycle (IGCC) projects and for projects that use other advanced coalbased generation technologies (ACBGT). For these types of projects, the aggregate credits available total up to $1.3 billion: $800 million for IGCC projects, and $500 million for ACBGT projects. Qualifying projects under Title XIII of EPAct2005 are not limited to technologies that employ carbon capture technologies; however, the Secretary of the Treasury is directed to give high priority to projects that include greenhouse gas capture capability. Under the same title of EPAct2005, certain projects employing gasification technology67 would be eligible to receive up to $650 million in tax credits, and these projects would also receive high priority from the Secretary of the Treasury if they include greenhouse gas capture technology.

ENCOURAGING TECHNOLOGY DEVELOPMENT IN THE ABSENCE OF A MARKET: ISSUES FOR CURRENT CARBON CAPTURE RD&D POLICY Each of the funding mechanisms described above — appropriations, loan guarantees, and tax credits — are examples of government ―pushing‖ carbon capture technologies (the upper left arrow in Figure 5) via direct spending and through private sector incentives. Thus far, however, these activities are taking place in a vacuum with respect to a carbon market or a regulatory structure. Lacking a price signal or regulatory mandate, it is difficult to assess whether a government-push approach is sufficient for long-term technology development.68 Some studies appear to discount the necessity of a price signal or regulatory mandate, at least initially, and place a higher priority on the successful demonstration of large-scale technological, economic, and environmental performance of technologies that comprise all of the components of an integrated CCS system: capture, transportation, and storage.69 So far, however, the only federally sponsored, fully integrated, large-scale CCS demonstration project — called FutureGen (see box) — failed in its original conception, which may have been due, in part, to the lack of a perceived market. DOE announced it was restructuring the FutureGen program because of its rising costs, which are difficult to assess against the project‘s ―benefits‖ without a monetary value attached to those benefits(i.e., the value of carbon extracted from the fuel and permanently

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sequestered). A carbon market would at least provide some way of comparing costs against benefits. One could argue that the benefits of CCS accrue to the amelioration of future costs of environmental degradation caused by greenhouse gas-induced global warming. Although it may be possible to identify overall environmental benefits to removing CO2 that would otherwise be released to the atmosphere, assigning a monetary value to those benefits to compare against costs is extremely difficult.

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TRYING TO PICK A WINNER: FUTUREGEN On February 27, 2003, President Bush proposed a 10-year, $1 billion project to build a coal-fired power plant that integrates carbon sequestration and hydrogen production while generating 275 megawatts of electricity, enough to power about 150,000 average U.S. homes. As originally conceived, the plant would have been a coal-gasification facility and produced between 1 and 2 million metric tons of CO2 annually. On January30, 2008, DOE announced that it was ―restructuring‖ the FutureGen program away from a single, state-of-the-art ―living laboratory‖ of integrated R&D technologies — a single plant — to instead pursue a new strategy of providing funding for the addition of CCS technology to multiple commercial-scale IGCC plants.70 In the restructured program, DOE would support up to two or three demonstration projects, each of at least 300 MW,71 and that would sequester at least 1 million metric tons of CO2 per year. In its budget justification for FY2009, DOE cited ―new market realities‖ for its decision, namely rising material and labor costs for new power plants, and the need to demonstrate commercial viability of Integrated Gasification Combined Cycle (IGCC) power plants with CCS.72 A policy question that emerged following the DOE‘s decision to scrap the original FutureGen concept was whether such a concept can be viable without a long-term price signal for carbon. FutureGen supporters have indicated that the rise in FutureGen‘s projected costs were consistent with the rise in global energy infrastructure projects due to inflation, implying that rising costs are not unique to FutureGen.73 Nevertheless, the reasons given by DOE in its decision to cancel the original concept are prima facie evidence that lack of a price signal for carbon in the face of known and rising costs for plant construction created too much uncertainty for the agency to continue the project. It is unclear whether a long-term price signal would have supported the FutureGen concept anyway, given the project‘s other uncertainties, such as its choice of a capture technology and disagreements over the private cost-share agreement.74

What Should the Federal Government Spend on CCS Technology Development? As discussed above, several studies underscore the value of a long-term price or regulatory signal to shape technological development and, presumably, to help determine a level of federal investment needed to encourage commercialization of an environmental technology such as carbon capture. As stated by Fischer:

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With respect to R&D for specific applications (such as particular manufacturing technologies or electricity generation), governments are notoriously bad at picking winners... [e.g., the breeder reactor]. The selection of these projects is best left to private markets while the government ensures those markets face the socially correct price signals.75

Despite the lack of regulatory incentives or price signals, DOE has invested millions of dollars since 1997 into capture technology R&D, and the question remains whether it has been too much, too little, or about the right amount. In addition to appropriating funds each year for the DOE program, Congress signaled its support for RD&D investment for CCS through provisions for tax credits available for carbon capture technology projects in EPAct2005, and through loan guarantees authorized in the Consolidated Appropriations Act for FY2008 (P.L. 110-161). Congress also authorized a significant expansion of CCS spending at DOE in the Energy Independence and Security Act of 2007 (EISA, P.L. 110140), which would authorize appropriations for a total of $2.2 billion from FY2008 through FY2013. Although EISA places an increased emphasis on large-scale underground injection and storage experiments, the legislation authorizes $200 million per year for projects that demonstrate technologies for the large-scale capture of CO2 from a range of industrial sources. Legislation has also been introduced in the 110th Congress that would authorize specific amounts of spending for CCS and capture technology development. Notably, the Carbon Capture and Storage Early Deployment Act (H.R. 6258), if enacted, would authorize distribution utilities76 to collect an assessment on fossil-fuel based electricity delivered to retail customers. The assessment would total approximately $1 billion annually, and would be issued by a corporation — established by referendum among the distribution utilities — as grants or contracts to private, academic, or government entities to accelerate commercial demonstration or availability of CO2capture and storage technologies and methods. This legislation contains elements that resemble, in many respects, recommendations offered in the MIT report.77 Some bills introduced in the 110th Congress include incentives such as tax credits, debt financing, and regulations to promote CO2 capture technology development. For example, S. 3132, the Accelerating Carbon Capture and Sequestration Act of 2008, provides a tax credit of $20 per metric ton of CO2 captured and stored.78 S. 3233, the 21st Century Energy Technology Deployment Act, would establish a corporation that could issue debt instruments (such as bonds) for financing technology development. A priority cited in S. 3233 is the deployment of commercial-scale CO2 capture and storage technology that could capture 10 million short tons of CO2 per year by 2015. A bill aimed at increasing the U.S. production of oil and natural gas while minimizing CO2 emissions, S. 2973, the American Energy Production Act of 2008, would require the promulgation of regulations for clean, coal-derived fuels. Facilities that process or refine such fuels would be required to capture 100% of the CO2 that would otherwise be released at the facility. Other legislation introduced invokes the symbolism of the Apollo program of the 1960s to frame proposals for large-scale energy policy initiatives that include developing CCS technology.79 The relevance and utility of large-scale government projects, such as the Apollo program, orthe Manhattan project, to developing carbon capture technology are explored in the following sections.

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Should the Federal Government Embark on a ―Crash‖ Research and Development Program? Some policymakers have proposed that the United States invest in energy research, development, and demonstration activities at the same level of commitment as it invested in the past during the Manhattan project and the Apollo program. As analogues to the development of technologies to reduce CO2 emissions and thwart long-term climate change, the Manhattan project and Apollo program are imperfect at best. They both had short-term goals, their success or failure was easily measured, and perhaps most importantly, they did not depend on the successful commercialization of technology and its adoption by the private sector. Nevertheless, both projects provide a funding history for comparison against CO2 capture technology cost projections, and as examples of large government-led projects initiated to achieve a national goal. The Manhattan project and Apollo program are discussed briefly below. The federal government‘s efforts to promote energy technology development in response to the energy crisis of the 1970s and early 1980s may be a richer analogy to CO2 capture technology development than either the Manhattan project or Apollo program. After the first oil crisis in 1973, and with the second oil crisis in the late 1970s, the national priority was to reduce dependence on foreign supplies of energy, particularly crude oil, through a combination of new domestic supplies (e.g., oil shale), energy efficiency technologies, and alternative energy supplies such as solar, among others. The success of these efforts was to have been determined, in part, by the commercialization of energy technologies and alternative energy supplies and their incorporation into American society over the long-term. Similarly, many analysts see the development of CCS technology as a necessary step needed over the next several decades or half-centuryto help alleviate human-induced climate change, which is itself viewed as a global problem for at least the next century or longer. As discussed more fully later, the outcome of the federal government‘s efforts to promote energy technologies in the 1970s and 1980s may be instructive to current approaches to develop CCS technology.

The Manhattan Project and Apollo Program The Manhattan project took place from 1942 to 1946.80 In July 1945, a bomb was successfully tested in New Mexico, and used against Japan at two locations in August 1945. In 1946, the civilian Atomic Energy Commission was established to manage the nation‘s future atomic activities, and the Manhattan project officially ended. According to one estimate, the Manhattan project cost $2.2 billion from 1942-1946 ($21 billion in 2007 dollars), greater than the original cost and time estimate of approximately $148 million for 1942 to 1944.81 The Apollo program encompassed 17 missions including six lunar landings that took place from FY1960 to FY1973.82 Although preliminary discussions regarding the Apollo program began in 1960, Congress did not decide to fund it until 1961 after the Soviets became the first country to send a human into space. The peak cost for the Apollo program occurred in FY1966 when NASA‘s total budget was $4.5 billion and its funding for Apollo was $3.0 billion.83 According to NASA, the total cost of the Apollo program for FY1960FY1973 was $19.4 billion ($95.7 billion in 2007 dollars).84 The first lunar landing took place

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in July 1969. The last occurred in December 1972. Figure 10 shows the funding history for both the Manhattan project and Apollo program.

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DOE-Supported Energy Technology Development The Department of Energy has its origins in the Manhattan project,85 and became a cabinet-level department in 1977,86 partly in response to the first oil crisis of 1973, caused in part by the Arab oil embargo. Another oil crisis (the ―second‖ oil crisis) took place from 1978-1981 as a result of political revolution in Iran. Funding for DOE energy R&D rose in the 1970s in concert with high oil prices and resultant Carter Administration priorities on conservation and development of alternative energy supplies. Crude oil prices fell during the 1980s and the Reagan Administration eliminated many energy R&D programs that began during the oil crisis years. Figure 10 shows the rise and fall of funding for DOE energy technology programs from 1974 to 2008. Comparisons to CO2 Capture R&D at DOE Current DOE spending on CCS technology development (discussed above) is far below levels of funding for the Manhattan project and Apollo program and for the energy technology R&D programs at their peak spending in the late 1970s and early 1980s. The development of CO2 capture technology is, of course, only one component of all federal spending on global climate change mitigation. However, the total annual federal expenditures on climate change, including basic research, are still far less than the Manhattan project and Apollo program, although similar to DOE energy technology development programs during their peak spending period.87 For comparison, the FY2008 budget and FY2009 budget request for DOE‘s energy technology R&D is approximately $3 billion per year. (See Figure 10.) Even if spending on CO2 capture technology were increased dramatically to Manhattan project or Apollo program levels, it is not clear whether the goal of developing a commercially deployable technology would be realized. As mentioned above, commercialization of technology and integration of technology into the private market were not goals of either the Manhattan project or Apollo program. For the Manhattan project, it did not matter what the cost was, in one sense, if a consequence of failing to build a nuclear weapon was to lose the war. For CO2 capture, the primary goal is to develop a technology that would be widely deployed and thus effective at removing a substantial amount of CO2 over the next half century or more, which necessarily requires its commercialization and widespread use throughout the utility sector. The Possibility of Failure: The Synthetic Fuels Corporation A careful study of one of the federal projects initiated in response to the energy crisis of the 1970s and early 1980s — the Synthetic Fuels Corporation (SFC) — may provide a valuable comparison to current thinking about the federal role in CO2 capture technology development: The government‘s attempt to develop a synthetic fuels industry in the late 1970s and early 1980s is a case study of unsuccessful federal involvement in technology development. In 1980, Congress established the Synthetic Fuels Corporation (SFC), a quasi-independent corporation, to develop large-scale projects in coal and shale liquefaction and gasification. Most of the projects centered on basic and conceptual work that would contribute to

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Larry Parker, Peter Folger and Deborah D. Stine demonstration programs in later stages, although funds were expended on several prototype and full-scale demonstration experiments. Formed in response to the 1970s energy crisis, the SFC was intended to support projects that industry was unable to support because of technical, environmental, or financial uncertainties. Federal loans, loan guarantees, price guarantees, and other financial incentives totaling $20 billion were authorized to spur industry action. Although SFC was designed to continue operating until at least 1992, the collapse in energy prices, environmental concerns, lack of support from the Reagan Administration, and administrative problems ended the synthetic fuels program in 1986.88 [citations from original text omitted]

One of the primary reasons commonly cited for the failure of the SFC was the collapse of crude oil prices during the 1980s, although other factors contributed.89 Without a stable and predictable price for the commodity that the SFC was attempting to produce in specific, mandated quantities, the structure of the SFC was unable to cope with market changes:

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The failure of the federal government‘s effort to create a synthetic fuels industry yields valuable lessons about the role of government in technology innovation. The synthetic fuels program was established without sufficient flexibility to meet changes in market conditions, such as the price of fuel. Public unwillingness to endure the environmental costs of some of the large-scale projects was an added complication. An emphasis on production targets was an added complication. An emphasis on production targets reduced research and program flexibility. Rapid turnover among SFC‘s high-level officials slowed administrative actions. The synthetic fuels program did demonstrate, however, that large-scale synthetic energy projects could be build and operated within specified technical parameters. 90 [citations from original text omitted]

Source: Congressional Research Service. Manhattan Project data: Richard G. Hewlett and Oscar E. Anderson, Jr., A History of the United States Atomic Energy Commission: The New World, 1939/1946,Volume I. Apollo program data: Richard Orloff, Apollo By The Numbers: A Statistical Reference, NASA SP-2000-4029, 2004 web update. DOE data: CRS Report RS22858, Renewable Energy R&D Funding History: A Comparison with Funding for Nuclear Energy, Fossil Energy, and Energy Efficiency R&D, by Fred Sissine. Figure 10. Annual Funding for the Manhattan Project, Apollo Program, and DOE Energy Technology Programs

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It may be argued that the demise of DOE‘s FutureGen program (as originally conceived, see box above) was partly attributable to the project‘s inflexibility in dealing with changing market conditions, in this case the rise in materials and construction costs and the doubling of FutureGen‘s original price estimate. However, the analogy between FutureGen and the SFC is limited. Although the SFC failed in part because of collapsing oil prices (the costs of the SFC program could be measured against the benefits of producing oil), for FutureGen the value of CO2 avoided (i.e. the benefit provided by the technology) was not even calculable for comparison to the costs of building the plant, because there is no real global price for CO2. The market conditions that contributed to the downfall of the SFC, however, could be very different from the market conditions that would arise following the creation of a price for CO2 emissions. The stability and predictability of the price signal would depend on the mechanism: carbon tax, allowance pricing, or auctions. A mechanism that allowed for a longterm price signal for carbon would likely benefit CO2 capture technology R&D programs.

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IMPLICATIONS FOR CLIMATE CHANGE LEGISLATION Any comprehensive approach to reducing greenhouse gases substantially must address the world‘s dependencyon coal for a quarter of its energy demand, including almost half of its electricity demand. To maintain coal as a key component in the world‘s energy mix in a carbon-constrained future would require developing a technology to capture and store its CO2 emissions. This situation suggests to some that any greenhouse gas reduction program be delayed until such carbon capture technology has been demonstrated. However, technological innovation and the demands of a carbon control regime are interlinked; therefore, a technology policy is no substitute for environmental policy and must be developed in concert with it.91 This linkage raises issues for legislators attempting to craft greenhouse gas reduction legislation. For the demand-pull side of the equation, the issue revolves around how to create the appropriate market for emerging carbon capture technologies. Table 3 compares four different ―price‖ signals across five different criteria that influence their effectiveness in promoting technology: Magnitude: Whatsizeof price signal or stringency of the regulation is imposed initially? Direction: What influences the direction (up or down) of the price signal or stringency of the regulation over time? Timing: How quickly is the price or regulation imposed and strengthened? Stability: How stable is the price or regulation over time? Duration: How long is the price or regulation imposed on affected companies?

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Larry Parker, Peter Folger and Deborah D. Stine

In general, the criteria suggest that regulation is the surest method of forcing the development of technology — price is not necessarily a direct consideration in decisionmaking. However, regulation is also the most limiting; technologies more or less stringent than the standard would have a limited domestic market (although foreign opportunities may be available), and development could be frozen if the standards are not reviewed and strengthened periodically. In contrast, allowance prices would provide the most equivocal signal, particularly if they are allocated free to participants. Experience has shown allowance prices to be subject to volatility with swings both up and down. The experience with the SO2 cap-and-trade program suggests the incentive can be improved with ―bonus‖ allowances; however, the eligibility criteria used could be perceived as the government attempting to pick a winner. In contrast, carbon taxes and allowance auctions (particularly 100% auctions with a reserve price) provide strong market-based price signals. A carbon tax is the most stable price signal, providing a clear and transparent signal of the value of any method of greenhouse gas reductions. Substantial auctioning of allowances also places a price on carbon emissions, a price that can be strengthened by incorporating a reserve price into the structure of the auction. However, each of these signals ultimately depends on the environmental goal envisioned and the specifics of the control program: (1) the stringency of the reduction requirement; (2) the timing of desired reductions; (3) the techniques allowed to achieve compliance. The interplay of these factors informs the technology community about the urgency of the need for carbon capture technology; the price signal informs the community what costperformance parameters are appropriate for the emerging carbon market. The nature of that price signal (regulatory, market, stability) informs the community of the confidence it can have that it is not wasting capital on a ―white elephant‖ or on a project that the market does not want or need. The issues for technology-push mechanisms are broader, and include not only the specifics of any reduction program and resulting price signal, but also international considerations and the interplay between carbon capture technology, storage, and the potential need for CO2 transport. Groups as diverse as The Pew Center, the Electric Power Research Institute, DOE, and MIT have suggested ―roadmaps‖ and other schemes for preparing carbon capture technology for a pending greenhouse gas reduction program.92 Generally, all of these approaches agree on the need for demonstration-size (200-300 MW) projects to sort out technical performance and cost effectiveness, and identify potential environmental and safety concerns. The Energy Independence and Security Act of 2007 (P.L. 110-140) reflected Congress‘ desire for more integrated demonstration projects, and DOE‘s restructured approach to FutureGen purportedly provides incentives for integrating capture technology on IGCC plants of 300 MW or greater.

Table 3. Comparison of Various Demand-Pull Mechanisms Mechanism Regulation

Magnitude Depends on available technology or performance standard

Direction Subject to periodic review by regulatory authorities based on technological progress

Timing Depends on frequency of regulatory review and pace of technological progress

Allowance Prices

Depends on stringency of emissions cap and other provisions of the cap-and-trade program Depends on level of tax

Market-driven based on the supply and demand for allowances Generally specified by legislation

Depends on environmental goal and specified schedule of emission reductions Depends on escalator provisions in legislation

Same dynamics as allowance prices unless legislation specifies a reserve price

Same dynamics as allowance prices unless legislation includes a reserve price — then it depends on any escalator clause

Carbon Tax

Same dynamics as allowances prices; can be strengthened by 100% auctioning of allowances and specifying a reserve price Source: Congressional Research Service.

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Allowance Auctions

Stability Very stable — can become stagnant if discourages further innovation or regulators rarely review standard Can be quite volatile

Stable

Allowance price volatility can be tempered by a reserve price and the specifics of the auctioning process

Duration Depends on the regulatory procedures for reassessment

Depends on environmental goal and specified schedule of emission reductions Depends on the specified schedule of the carbon tax Same as for allowance prices, but includes the details of the auctioning procedures

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Finally, it should be noted that the status quo for coal with respect to climate change legislation isn‘t necessarily the same as ―business as usual.‖ The financial markets and regulatory authorities appear to be hedging their bets on the outcomes of any federal legislation with respect to greenhouse gas reductions, and are becoming increasingly unwilling to accept the risk of a coal-fired power plant with or without carbon capture capacity. This sort of limbo for coal-fired powerplants is reinforced by the MIT study, which makes a strong case against subsidizing new construction (allowed for IGCC under the EPAct2005) without carbon capture because of the unattractive costs of retrofits: Coal plants will not be cheap to retrofit for CO2 capture. Our analysis confirms that the costs to retrofit an air-driven SCPC [supercritical pulverized coal] plant for significant CO2 capture, say 90%, will be greater than the costs to retrofit an IGCC plant. However, ... the modifications needed to retrofit an IGCC plant for appreciable CCS are extensive and not a matter of simply adding a single simple and inexpensive process step to an existing IGCC plant.... Consequently, IGCC plants without CCS that receive assistance under the 2005 Energy Act will be more costly to retrofit and less likely to do so. The concept of a “capture ready” IGCC or pulverized coal plant is as yet unproven and unlikely to be fruitful. The Energy Act envisions ―capture ready‖ to apply to gasification technology. [citation omitted] Retrofitting IGCC plants, or for that matter pulverized coal plants, to incorporate CCS technology involves substantial additional investments and a significant penalty to the efficiency and net electricity output of the plant. As a result, we are unconvinced that such financial assistance to conventional IGCC plants without CCS is wise.93 [emphasis in original]

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As noted earlier, lack of a regulatory scheme (or carbon price) presents numerous risks to any research and development effort designed to develop carbon capture technology. Ultimately, it also presents a risk to the future of coal.

End Notes 1

Pew Center on Global Climate Change, Coal and Climate Change Facts, (2008), available at [http://www.pewclimate.org/global-warming-basics/coalfacts.cfm]. 2 International Energy Agency, World Energy Outlook 2007: China and India Insights (2007), pp. 593. 3 World, China and India statistics from International Energy Agency, World Energy Outlook 2007: China and India Insights, (2007), pp. 592, 596, and 600; United States statistics from Energy Information Administration, Annual Energy Review: 2005 (July 2006), p. 228. 4 Pew Center on Global Climate Change, Coal and Climate Change Facts (2008), available at [http://www.pewclimate.org/global-warming-basics/coalfacts.cfm]. Capacity factor derived by CRS from data presented, assumingplants would operate in baseload mode with 70% capacity factors. 5 For a general discussion of carbon capture and sequestration, see CRS Report RL33801, Carbon Capture and Sequestration (CCS), by Peter Folger. 6 For more information on policy issues related to the transportation of CO2, see CRS reports RL33971: Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy Issues, and CRS Report RL34316, Pipelines for Carbon Dioxide (CO2 ) Control: Network Needs and Cost Uncertainties, by Paul W. Parfomak and Peter Folger. 7 For a useful summary of carbon capture technology, see Steve Blankinship, ―The Evolution of Carbon Capture Technology Part 1,‖ Power Engineering (March 2008). 8 Ryan M. Dailey and Donald S. Shattuck, ―An Introduction to CO2 Capture and Sequestration Technology, Utility Engineering‖ (May 2008), p. 3. 9 Massachusetts Institute of Technology, The Future of Coal: An Interdisciplinary MIT Study (2007), p. 147. Hereafter referred to as MIT, The Future of Coal.

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Levelized cost is the present value of the total cost of building and operating a generating plant over its economic life, converted to equal annual payments. Costs are levelized in real dollars (i.e., adjusted to remove the impact of inflation). 11 MIT, The Future of Coal, pp. 27, 149. 12 Ryan M. Dailey and Donald S. Shattuck, ―An Introduction to CO2 Capture and Sequestration Technology, Utility Engineering‖ (May 2008), p. 4. 13 Ibid, p. 5. 14 Steve Blankinship, ―The Evolution of Carbon Capture Technology, Part 1,‖ Power Engineering (March 2008), p. 30. 15 Slipstream refers to pilot testing at an operating power plant using a portion of the flue gas stream. 16 AEP News Release, RWE to Join AEP in Validation of Carbon Capture Technology, (November 8, 2007). 17 Ryan M Dailey and Donald S. Shattuck, ―An Introduction to CO2 Capture and Sequestration Technology, Utility Engineering‖ (May 2008), p. 7. 18 Powerspan Corp., Carbon Capture Technology for Existing and New Coal-Fired Power Plants (April 15, 2008). 19 IGCC is an electric generating technology in which pulverized coal is not burned directly but mixed with oxygen and water in a high-pressure gasifier to make ―syngas,‖ a combustible fluid that is then burned in a conventional combined-cycle arrangement to generate power. 20 MIT, The Future of Coal, p. 35. 21 MIT, The Future of Coal, p. 36. 22 Brad Kitchens and Greg Litra, ―Restructuring FutureGen,‖ Electric Light & Power, (May/June 2008), pp. 46-47, 58. 23 MIT, The Future of Coal, pp. 30-31. 24 For more information, see Vattenfall‘s website at [http://www.vattenfall.com/www/ co2_en/co2_en/879177tbd/ 879211pilot/index.jsp] 25 For more information, see ES Energy‘s website at [http://www.csenergy.com.au/ research_and_development/ oxy_fuel_news.aspx]. 26 MIT, The Future of Coal, p. 147. 27 MIT, The Future of Coal, pp. 30, 149. 28 Steve Blankinship, ―The Evolution of Carbon Capture Technology, Part 2,‖ Power Engineering (May 2008), pp. 62-63. 29 DOE National Energy Technology Laboratory, Carbon Sequestration FAQ Information Portal, at [http://www.netl.doe.gov/technologies/carbon_seq/FAQs/tech-status.html#]. 30 For example, the American Electric Power (AEP) Mountaineer Plant in West Virginia is planning to capture about 90% of CO2 from 15 MW(e) of the plant‘s output (equivalent to about 100,000 metric tons of CO2 per year) beginning in 2010. 31 For example, see Interlaboratory Working Group, Scenarios for a Clean Energy Future, ORNL/CON-476 (November 2000). 32 For example, see CERA Advisory Service, Design Issues for Market-based Greenhouse Gas Reduction Strategies; Special Report (February 2006), p. 59; Congressional Budget Office, Evaluating the Role of Prices and R&D in Reducing Carbon Dioxide Emissions (September 2006). 33 Richard D. Morgenstern, Climate Policy Instruments: The Case for the Safety Valve (Council on Foreign Relations, September 20-21, 2004), p. 9. 34 Carolyn Fischer, Climate change Policy Choicesand Technical Innovation, Resources for the Future Issue Brief #20 (June 2000), p. 2. 35 State Corporation Commission, Application of Appalachian Power Company, Case No. PUE-2007-00068 (Richmond, April 14, 2008), p. 16. 36 As stated by DOE: ―Regulatory uncertainty for GHG legislation is a key issue impacting technology selection and reliability of economic forecasts. Returns on investment for conventional plants, including supercritical, can be severely compromised by the need to subsequently address CO 2 mitigation. Higher capital costs incurred for IGCC may make such new plants less competitive unless their advantage in CO 2 mitigation is assured.‖ DOE National Energy Technology Laboratory, Tracking New Coal-fired Power Plants (June 30, 2008), p. 14. 37 Citi, Morgan Chase, and Morgan Stanley, The Carbon Principles: Fossil Fuel Generation Financing Enhanced Environmental Diligence Process (February 2008), p. 1. 38 Exceptions to this would include areas where the carbon dioxide could be used for EOR, or where a state or region has enacted greenhouse gas controls, such as California and several northeastern states. 39 For a fuller discussion of the uncertainties involved in estimating the cost of cap-and-trade programs, see CRS Report RL34489, Global Climate Change: Costs and Benefits of S. 2191 (S. 3036), by Larry Parker and Brent Yacobucci. 40 Segey Paltsev, et al., Assessment of U.S. Cap-and-Trade Proposals, MIT Joint Program on the Science and Policy of Global Change, Report 146 (April 2007), p. 16. 41 The Clean Air Act, Section 111 (42 U.S.C. 7411).

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Donald Shattuck, et al., A History of Flue Gas Desulfurization (FGD)— The Early Years, UE Technical Paper (June 2007), p. 3. 43 For a fuller discussion of EPA authority to regulate greenhouse gases under the Clean Air Act, see Robert J. Meyer, Principal Deputy Assistant Administrator, Office of Air and Radiation, EPA Testimony before the Subcommittee on Energy and Air Quality, Committee on Energy and Commerce, U.S. House of Representation (April 10, 2008). 44 For a discussion of the structure of the Clean Air Act, see CRS Report RL30853: Clean Air Act: A Summary of the Act and Its Major Requirements, by James E. McCarthy, Claudia Copeland, Larry Parker, and Linda-Jo Schierow. 45 42 U.S.C. 7411, Clean Air Act, Sec. 111(a)(1) 46 40 CFR 60.40-46, Subpart D — Standards of Performance for Fossil-Fuel-Fired Steam Generator for Which Construction is Commenced After August 17, 1971. 47 Margaret R. Taylor, The Influence of Government Actions on Innovative Activities in the Development of Environmental Technologies to Control Sulfur Dioxide Emissions from Stationary Sources, Thesis, Carnegie Institute of Technology (January 2001), p. 37, 40. 48 Fri v. Sierra Club, 412 US 541 (l973). This decision resulted in EPA issuing ―prevention of significant deterioration‖ regulations in 1974; regulations what were mostly codified in the 1977 Clean Air Amendment (Part C). 49 Taylor, ibid., p. 37. 50 Taylor, ibid., p. 39. 51 For a discussion of challenges arising from the early development of FGD, see Donald Shattuck, et al., A History of Flue Gas Desulfurization (FGD) — The Early Years, UE Technical Paper (June 2007). 52 Examples include full-page ads in the Washington Post entitled ―Requiem for Scrubbers,‖ ―Scrubbers, Described, Examined and Rejected,‖ and ―Amen.‖ For an example, see Washington Post, p. A32 (October 25, 1974). 53 40 CFR 60.40Da-52Da, Subpart Da — Standards of Performance for Electric Utility Stream Generating Units for Which Construction is Commenced After September 18, 1978. 54 Margaret R. Taylor, Edward S. Rubin, and David A. Hounshell, ―Control of SO2 Emissions from Power Plants: A Case of Induced Technological Innovation in the U.S.,‖Technological Forecasting & Social Change (July 2005), p. 697. 55 Shattuck, et. al., p. 15. 56 Congressional Budget Office, Evaluating the Roles of Prices and R&D in Reducing Carbon Dioxide Emissions (September 2006), p. 17. 57 In addition, some of the revenue generated by the tax could be used to fund research, development, demonstration, and deployment of new technology to encourage the long-term transition to a less-carbonintensive economy. 58 For a fuller discussion, see CRS Report RL33799, Climate Change: Design Approaches for a Greenhouse Gas Reduction Program, by Larry Parker. 59 Margaret R. Taylor, Edward S. Rubin, and David A. Hounshell, ―Effect of Government Actions on Technological Innovation for SO2 Control,‖ Environmental Science & Technology (October 15, 2003), p. 4531. In a more recent article, the authors state: ―Finally, the case provides little evidence for the claim that cap-and-trade instruments induce innovation more effectively than other instruments.‖ Margaret R. Taylor, Edward S. Rubin, and David A. Hounshell, ―Control of SO2 Emissions from Power Plants: A Case of Induced Technological Innovation in the U.S.,‖ Technological Forecasting & Social Change (July 2005), p. 697-8. 60 Like a carbon tax, the revenues received could be at least partly directed toward research, development, and demonstration programs. 61 Karsten Neuhoff, Auctions for CO2 Allowances — A Straw Man Proposal, University of Cambridge Electricity Policy Research Group (May 2007), pp. 3-6. A short-squeeze is a situation where the price of a stock or commodity rises and investors who sold short (believing the price was going to fall) rush tobuy it to cover their short position and cut their losses. 62 Personal communication, Timothy E. Fout, General Engineer, DOE National Energy Technology Laboratory, Morgantown, WV (July 16, 2008). 63 CCS research and development program line item in the DOE budget (part of the Office of Fossil Energy), U.S. Department of Energy, FY2009 Congressional Budget Request, Volume 7, DOE/CF-030 (Washington, DC, February 2008). 64 Ibid. 65 Beginning in 2003, DOE created seven regional carbon sequestration partnerships to identify opportunities for carbon sequestration field tests in the United States and Canada. 66 The explanatory statement was published with the Committee Print of the House Committee on Appropriations, Consolidated Appropriations Act, 2008, H.R. 2764/Public Law P.L. 110-161. The Committee Print, which was published in January 2008, is available at [http://www.gpoaccess.gov/congress/ house/appropriations/ 08conappro.html].

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Under Title XIII of EPAct2005, gasification technology means any process which converts a solid or liquid product from coal, petroleum residue, biomass, or other materials, which are recovered for their energy or feedstock value, into a synthesis gas (composed primarily of carbon monoxide and hydrogen) for direct use in the production of energy or for subsequent conversion to another product. 68 See quote by Morgenstern above. In that analysis, government-supported research is needed to compensate for market imperfections. In the current situation, there is no market, and thus its imperfections are moot. 69 MIT, The Future of Coal, p. xi. 70 See [http://www.fossil.energy.gov/news/techlines/2008/08003-DOE_Announces_ Restructured_FutureG.html]. 71 See [http://www.fossil.energy.gov/news/techlines/2008/08013-DOE_Takes_Next_Steps_ With_Restruct.html]. 72 DOE FY2009 Budget Request, p. 16. 73 FutureGen Alliance press release (April 15, 2008), at [http://www.futuregenalliance.org/ news/releases/pr_04-1508.stm]. 74 See, for example, Michael T. Burr, ―Death of a Turkey, DOE‘s Move to ‗Restructure‘ FutureGen Clears the Way for a More Rational R&D,‖ Public Utilities Fortnightly (March 2008); and David Goldston, ―Demonstrably Wrong,‖ Nature, Vol. 453, No. 16 (April 30, 2008), p. 16. 75 Carolyn Fischer, Climate Change Policy Choices and Technical Innovation, Resources for the Future Climate Issue Brief #20 (June 2000), p. 9 76 A distribution utility is defined in the legislation as an electric utility that has a legal, regulatory, or contractual obligation to deliver electricity directly to retail customers. 77 MIT, The Future of Coal, p. 102. 78 S. 3132 would also provide a $10 per metric ton credit for CO2 captured and used as a tertiary injectant in an enhanced oil and natural gas recovery project. 79 For example, H.R. 2809, the New Apollo Energy Act of 2007; and H.R. 6385, the Apollo Energy Independence Act of 2008. 80 U.S. Department of Energy, Office of History and Heritage Resources, ―The Manhattan Project: An Interactive History,‖ webpage at [http://www.cfo.doe.gov/me70/ manhattan/1939-1942.htm]. F.G. Gosling, The Manhattan Project: Making the Atomic Bomb, January 1999 edition (Oak Ridge, TN: Department of Energy). 81 Richard G. Hewlett and Oscar E. Anderson, Jr., A History of the United States Atomic Energy Commission: The New World, 1939/1946 ,Volume I, (University Park, PA: The Pennsylvania State University Press, 1962). Appendix 2 provides the annual Manhattan project expenditures. These costs were adjusted to 2007 dollars using the price index for gross domestic product (GDP), available from the Bureau of Economic Affairs, National Income and Product Accounts Table webpage, Table 1.1.4., at [http://www.bea.gov/bea/dn/ nipaweb/]. 82 There is some difference of opinion regarding what activities comprise the Apollo program, and thus when it begins and ends. Some include the first studies for Apollo, Skylab, and the use of Apollo spacecraft in the Apollo-Soyuz Test Project. This analysis is based on that provided by the National Aeronautics and Space Administration (NASA), which includes the first studies of Apollo, but not Skylab or Soyuz activities, in a 2004 web update by Richard Orloff of its publication entitled Apollo By The Numbers: A Statistical Reference, NASA SP-2000-4029, at [http://history.nasa.gov/SP-4029/Apollo_00_ Welcome.htm]. 83 The funding data is available at [http://history.nasa.gov/SP-4214/app2.html#1965]. It is based on information in NASA, The Apollo Spacecraft - A Chronology, NASA Special Publication-4009, at [http://www.hq.nasa.gov/office/pao/History/SP-4009/contents.htm]. This data is from Volume 4, Appendix 7 at [http://www.hq.nasa.gov/office/pao/History/ SP-4009/v4app7.htm]. 84 Richard Orloff, Apollo By The Numbers: A Statistical Reference, NASA SP-2000-4029, 2004 web update, at [http://history.nasa.gov/SP-4029/Apollo_00_Welcome.htm]. The funding data is available at [http://history.nasa.gov/SP-4029/Apollo_18-16_Apollo_ Program_Budget_Appropriations.htm]. It is based on information in NASA, The Apollo Spacecraft - A Chronology, NASA Special Publication-4009, at [http://www.hq.nasa.gov/ office/pao/History/SP-4009/contents.htm]. 85 Department of Energy, ―Origins & Evolution of the Department of Energy,‖ webpage at [http://www.doe.gov/ about/origins.htm]. 86 The Department of Energy Organization Act of 1977 (P.L. 95-91). 87 CRS estimates that budget authority for federal climate change programs was $5.44 billion in FY2007. See CRS Report RL33817, Climate Change: Federal Funding and Tax Incentives, by Jane A. Leggett. 88 The National Academy of Sciences, ―The Government Role in Civilian Technology: Building a New Alliance‖ (National Academy Press, Washington, DC, 1992), pp. 58-59. 89 For a variety of reasons, Canada‘s experience with producing synthetic fuels, specifically oil sands development, has differed from the U.S. experience. For more information, see CRS Report RL34258, North American Oil Sands: History of Development, Prospects for the Future, by Marc Humphries. 90 Ibid., p. 59. 91 Carolyn Fischer, Climate Change Policy Choices and Technical Innovation, Resources for the Future Climate Issue Brief #20 (June 2000), p. 9.

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Larry Parker, Peter Folger and Deborah D. Stine

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For example, see Pew Center on Global Climate Change, Coal and Climate Change Facts, (2008), available at [http://www.pewclimate.org/global-warming-basics/coalfacts.cfm]; Coal Utilization Research Council and Electric Power Research Institute technology roadmap at [http://www.coal.org/roadmap/]; DOE Energy, National Energy Technology Laboratory, Carbon Sequestration Technology Roadmap and Program Plan 2007 available at [http://www.netl.doe.gov/technologies/carbon_seq/refshelf/project%20portfolio/ 2007/2007Roadmap.pdf; and, MIT, The Future of Coal, pp. xi-xv. 93 MIT, The Future of Coal, pp. 98-99.

In: Clean Coal Editor: Klaes G. Douwe

ISBN: 978-1-60741-358-5 © 2010 Nova Science Publishers, Inc.

Chapter 2

CLEAN COAL TECHNOLOGY HEARING United States Government Printing Office The committee met, pursuant to notice, at 9:28 a.m. in room SD– 366, Dirksen Senate Office Building, Hon. Jeff Bingaman, chairman, presiding.

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OPENING STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM NEW MEXICO The Chairman. OK, why don‘t we start the hearing. I‘m informed Senator Domenici is going to be a little late, but that we should proceed without him and he will catch up once he gets here. Let me just make a few comments, and then we have two excellent panels this morning. We‘ll just start with panel one, but let me make these comments first. Thank you all very much for coming. We‘re hoping to learn more about the latest advances in clean coal technology as part of this hearing. This is a very important subject that the committee is spending a lot of time on this year. This is the third hearing we‘ve had on coal, so far this year. I think it‘s important that we try to understand the policy, and what the right policy should be, with regard to this very important resource. Coal-fired generation supplies over half, or about half of the electricity that we consume in the United States. The Energy Information Administration predicts that that share will at least stay constant and perhaps even increase over the next 20 to 30 years. Coal is likely to remain a prominent part of our energy supply, both because it‘s cheap and because it‘s abundant. Importantly, it is also true that in other countries, particularly the fast-developing countries of India and China. They have an unprecedented demand for energy. China, for example, has plans to build over 500 new coal-fired power plants in the coming years, that we know about. It‘s estimated that a new plant opens there every few weeks, or every week is the estimate, every week to ten days.

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If this expansion is accomplished using the sub-critical pulverized coal technology that we still use predominantly here and throughout the world, the implications for solving our global warming problems are serious. The United States, largely through the good works of the National Laboratories, has been a leader in the development of clean coal technology. Over the last few decades technologies have been produced and policies have been implemented, to significantly reduce emissions of pollutants, such as sulfur dioxide and nitrogen oxides and mercury. The next challenge is to deal with the issue of carbon dioxide emissions from coal generation. Today, those emissions are roughly double the emissions produced from burning natural gas. We‘ve reached some measure of consensus around the Congress that global warming is a problem we need to address. I think where we lack consensus is on how to address it. I expect that we will be having debates on that subject even before this session of the Congress is over. I think what we need to be doing in the interim, of course, is determining how we can go about reducing emissions and what timeframe we need to follow. This latter point of timing is very important, not only because of the pace of construction in India and in China that I mentioned, but also, when we do arrive at an approach to regulating green house gas emissions that puts a price on carbon dioxide, we need to try to have technologies identified that can be deployed. Given a long lead time of five to 10 years between design and operation that we have seen for many of these projects, one could imagine a scenario where it could be actually decades before these technologies would be determined to be commercially viable and ready for widespread deployment. So, we need to avoid that, if at all possible. I hope that in addition to developing these advanced technologies, we can collectively come up with some creative ways to compress the timeframe for commercial deployment of the technologies. I hope some of the testimony today will help us with regard to that. Let me just introduce the first panel. Carl Bauer, who is the Director of the National Energy Technology Laboratory in Morgantown, West Virginia is here. Thank you for being here, Carl. Jerry Hollinden, who is the Senior Vice President of Power Business Line, URS Corporation in Louisville, Kentucky. Thank you for being here. Jeffrey Phillips, who‘s the Program Manager for Advanced Coal Generation with EPRI out of Charlotte, North Carolina. Thank you for being here. So, why don‘t you folks go right ahead? Senator Barrasso and I will hear your testimony and then have some questions.

STATEMENT OF CARL O. BAUER, DIRECTOR, NATIONAL ENERGY TECHNOLOGY LABORATORY, DEPARTMENT OF ENERGY Mr. Bauer. Thank you, Mr. Chairman, members of the committee. Obviously, with the introduction, Senator, you obviously are well-informed, as is the committee, and we thank you for your interest. Economic prosperity in the United States over the past century has relied heavily on the abundance of fossil fuels in North America. Making full use of this domestic asset in a responsible manner has been, and will be, an essential part of how our country fulfills its

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energy requirements, minimize the detrimental environmental impacts, and positively contributes to National security and well being. Given current technologies, coal prices, and the rates of consumption, the United States has approximately a 250-year supply of coal available. Coal-fired power plants supply over half of our electricity, and are essential to continue to do so through at least the mid-century. Several overarching issues characterize the current energy situation in the United States: environmental quality, energy affordability, and supply security. A resolution of these challenges depends in part from the development and deployment of technologies that are the result of design and implementing a timely and properly tiered researched development and demonstration strategy. DOE is developing a portfolio of technologies that will lead to cost-effective, near-zero atmospheric emissions technologies, including green house gases. But both the future and existing fleet of coal-based energy plants. The RD&D program is divided into a coal R&D program and a demonstration component. The success of the clean coal R&D will ultimately be judged by the extent to which emerging technologies get deployed in domestic and international marketplaces. Deploying technologies into the international marketplace requires that the technologies address environmental and operational performance requirements, as well as financial challenges relative to the ability of plants to dispatch or sell its electricity at an acceptable place in the auction, which characterizes the access to the market needed to gain adequate return on investment for the utilities. This includes, in the regulated market, the ability to recover cost in the rate-base, the technical and financial risks associated with the deployment of new coal technologies are key factors in determining whether they will achieve success in the marketplace, and are often difficult to overcome for new technologies seeking to make entry. In 1985, the Congress authorized DOE to initiate the clean coal technology demonstration program to provide additional impetus to move technologies from the laboratories to the marketplace. This program evolved into the power plant improvement initiative and then to the clean coal power initiative at present. The purpose of this cost-shared program was to develop and demonstrate at commercial scale, innovative technologies that would help industry to meet the strict environmental requirements, and yet not impinge on the economy of the United States. More than 20 technologies from the program have achieved commercial success in technologies that are related to low-NOX burners, selective catalytic reduction, flue gas desulphurization, fluid- bed combustion, and now mercury. The National Research Council estimated that these technologies have yielded sales totaling more than $27 billion. Announcements of the third solicitation under CCPI is planned in this year. The focus is on carbon capture and storage technologies. Fossil Energies core R&D program provides for the development of new cloth and environmentally effective approaches to use coal at predemonstration scale. These include advanced research, advanced turbines and hydrogen turbines, carbon sequestration and capture, fuel cells gasification, hydrogen and fuels production, and innovation for existing plants. Details on these programs are in my written testimony. Today, nearly three out of every four coal-burning power plants in this country, is equipped with technologies that can trace their roots back to the clean coal technology program.

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For example, the current generation of low-NOX burners alone, is a major clean coal story. Nearly $1.5 billion of these burners have been sold and installed. Selective catalytic reduction now costs half what it did in the 1980‘s and systems are on order or under construction for 30 percent of the coal-fired power plants. Flue gas scrubbers are a third of their cost compared to the 1970‘s and are more reliable, less costly, and more efficient. Fluidized-bed technology development in the core coal R&D program was first demonstrated in that program and has recorded global sales of over $10 billion. In Tampa, Florida and West Terra Haute, Indiana, the first pioneering full-size coal gasification power plants, IGCCs, have opened a new pathway for the next generation of clean fuel flexible power plants. More recently within the coal R&D program, the carbon sequestration regional partnerships have brought an enormous amount of capability and experience together to work on the challenge of both infrastructure development and storing huge volumes of CO2 underground permanently. Together with DOE, the partnerships secure the active participation of more than 500 entities representing more than 350 industrial companies, engineering firms, State agencies, non-governmental organizations, and other supporting organizations. The partnerships are conducting field tests to validate the efficacy of carbon capture and storage technologies and a variety of geologic and terrestrial storage sites throughout the United States and Canada. Extensive data information gathered during the initial stages of the project, of the seven partnerships, identified the most promising opportunities for carbon sequestration in their regions and are performing 25 geologic field sites and 11 terrestrial field tests. In conclusion, DOEs clean coal R&D program has a successful track record and a promising future that will ultimately lead to pollution-free coal plants. Mr. Chairman and members of the committee, this completes my statement and I‘d be happy to take any questions you have. [The prepared statement of Mr. Bauer follows:]

Prepared Statement of Carl O. Bauer, Director, National Energy Technology Laboratory, Department of Energy Thank you Mr. Chairman and Members of the Committee. I appreciate this opportunity to provide testimony on the Department of Energy‘s (DOE‘s) Clean Coal Research and Development (R&D) Program. The economic prosperity of the United States over the past century has been built upon an abundance of fossil fuels in North America. The United States‘ fossil fuel resources represent a tremendous national asset. Making full use of this domestic asset in a responsible manner enables the country to fulfill its energy requirements, minimize detrimental environmental impacts, and positively contribute to national security. Given current technologies, coal prices, and rates of consumption, the United States has approximately a 250-year supply of coal available. Coal-fired power plants supply about half of our electricity and are expected to continue to do so through mid-century. Because electricity production increases at a rate of about 2% per year, the rate of coal use will increase proportionally. However, the continued use of this secure domestic resource will be

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dependent on the development of cost- effective technology options to meet both economic and environmental goals, including the reduction of greenhouse gas emissions.

Energy Issues Facing the United States Several overarching issues characterize the current energy situation in the United States. Their resolution depends in part on designing and implementing a timely and properly tailored research, development, and demonstration strategy, which could help sustain economic growth in the United States. The major issues are energy affordability and supply security, and environmental quality.

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Energy Affordability and Supply Security The availability of affordable energy has been instrumental in helping establish the United States‘ economic engine. The relatively recent escalation in energy prices, particularly in oil and natural gas, stem, in large measure, from the global competition for these energy resources. In particular, as economies in China, India, and other countries in the developing world expand to meet the demands of their huge populations, their impact on world markets will increase through increased competition for oil and gas supplies. Further complicating this issue are socio-political and other influences that can affect the energy market. Despite gains in energy efficiency and projected conservation, stemming in part from higher prices, the Energy Information Agency (EIA) projects that the U.S. will require increasing amounts of energy through 2030, the last year that EIA models. Even after accounting for growing contributions from renewable energy and nuclear, our domestic coal resources will be required to provide an affordable portion of our growing needs.

Environmental Quality All fossil fuels incorporate carbon and all contain, to greater or lesser degrees, undesirable components, such as sulfur, nitrogen, and other trace elements, that can potentially harm the earth‘s biota. It has long been recognized that coal-fired power plants emit sulfur and nitrogen containing compounds that combine with the moisture in the atmosphere to produce acid rain, and even acid snow. The generation of acid rain is not limited to local regions around the power plant. These acid forming emissions are often carried over hundreds to thousands of miles by wind currents where they are deposited to earth through rain or snow. In addition to sulfur and nitrogen compounds, coal power plants are also known to emit particulates that can, if unmitigated, lead to harmful health effects. Air toxics is a term used to describe atmospheric pollutants that, if unmitigated, can also cause serious health effects. Air toxics include heavy metals, volatile organics, dioxins, and mercury. Relative to fossil fuel use, mercury has been the focus of recent attention and

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regulatory action. Mercury health effects are still being investigated but have, thus far, been linked to neurological, cardiovascular, and respiratory illnesses. Currently, there is growing consensus that increased levels of greenhouse gases in the atmosphere, primarily carbon dioxide, methane, nitrous oxide, and chlorofluorocarbons, are linked to climate change. In this connection, fossil fuel use has been identified as a major source of anthropogenic greenhouse gas emissions, particularly carbon dioxide, into the atmosphere. Slowing the growth of anthropogenic greenhouse gas emissions has become an important concern. The production of electricity using fossil, nuclear, and renewables requires large quantities of water and produces waste byproducts. In the United States, thermoelectric power plants utilize more than 130 billion gallons of water per day. With water supply and availability issues becoming more acute across the major growth areas of the United States, the energy industry will need to take bold steps to conserve water, while meeting all environmental requirements. Coal-fired power plants also produce more than 120 million tons of solid waste byproducts each year. While 40% of these are re-used in various markets, the remainder is deposited into landfills and requires careful management and monitoring to prevent harmful environmental impacts. Ensuring environmental quality is not a simple matter. Environmental requirements are becoming increasingly stringent and require new technologies to address the challenges of regulatory compliance. The use of fossil fuels is clearly essential for the foreseeable future. Therefore, industry, and where appropriate in collaboration with the public sector and others, must reduce the environmental impact of utilization of these fuels.

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How is DOE Responding to the Issues The Office of Fossil Energy (FE) recognizes the complex energy challenges facing America today. Its programs are directly responding to the issues laid out above, as well as to the direction provided by Congress and the Administration. To ensure a secure energy future for the United States, the Nation must commit to energy efficiency and renewable energy, but it also must promote the cleaner and more productive use of domestic energy resources, including coal, oil, and natural gas. The following key thrusts in Fossil Energy‘s research portfolio will lead the way in enhancing energy security from fossil fuels. Near-Zero Atmospheric Emissions Energy.—DOE is spearheading an R&D effort called FutureGen that will utilize technology developments from the core R&D program to provide near-zero atmospheric emissions clean coal power plants—including carbon capture and sequestration—that could ultimately be built at costs comparable to current day technology. Together with its supporting technologies for reducing all criteria pollutants, FutureGen will help to ensure that coal-fired power plants meet the most stringent environmental requirements. Climate Change.—DOE conducts R&D that contributes to expanding the options for meeting near-term greenhouse gas intensity goals, set by President Bush in the Global Climate Change Initiative. By meeting the near-term intensity goals, the longer-term goal of atmospheric greenhouse gas stabilization will become more achievable. Federal investment in climate change mitigation technologies has one overriding benefit: a broad suite of such

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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:

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Accelerate the development of new energy technologies beyond the pace that would otherwise be dictated by normal market or regulatory forces. Expand the slate of beneficial energy options beyond those likely to be developed by the private sector on its own. Potentially result in revolutionary ―breakthrough‖ technologies that achieve environmental, efficiency, and/or cost goals well beyond those currently pursued by the private sector. The Federal R&D program is working to provide advanced technology options that are significantly more effective and affordable than today‘s limited set of fossil energy technologies. The success of this activity could not only benefit current power stations but also strengthen the technical foundation for the next generation of coal- fueled power plants—serving to preserve energy diversity and strengthen domestic energy security. The Federal presence in this type of R&D may also provide scientifically sound data for future governmental regulatory and policy decisions. Similarly, the current uncertainty regarding future regulation of CO2 is not conducive to significant private-sector investment in greenhouse gas mitigation technologies. The Federal R&D program, therefore, is developing a wide range of potential carbon mitigation approaches—such as carbon sequestration—that can be used by the private sector for future investment opportunity. Every year, DOE conducts a benefit analysis to quantify and highlight the significant economic and energy-sector benefits attributable to R&D programs. Estimated impacts on oil and gas production, oil imports, power generation technology market penetration, carbon intensity, and fuel prices are the basis for estimating economic, environmental, and energy security benefits from FE‘s R&D programs.

Private-Sector R&D Issues Within the electric power industry, R&D investments have been historically modest. The National Science Foundation estimates utility-funded R&D at $114 million in 2001. Nationally, the production of electricity consumes over 40 quadrillion British thermal units of

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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 coalbased energy plants. The RD&D Program is divided into a demonstration component and a core R&D program.

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Demonstration Program The success of Clean Coal R&D will ultimately be judged by the extent to which emerging technologies get deployed in domestic and international marketplaces. The technical and financial risks associated with the deployment of new coal technologies are key factors determining whether they will achieve success in the marketplace. In 1985, the Congress authorized DOE to initiate the Clean Coal Technology Demonstration Program to provide additional impetus to move technology from the laboratory to the marketplace. The purpose of the program was to develop and demonstrate, at commercial scale, a family of innovative technologies that would help industry to meet the strict environmental requirements that were ultimately contained in the Clean Air Act Amendments of 1990. The Program was developed as a Government/industry cost-shared partnership and DOE‘s cost share was limited to a maximum of 50% of the funding for each participating project. The first projects were started in 1987. These projects were selected in the first of five rounds of competition. Over the course of the program, 34 projects have been completed. The total cost of these five rounds was approximately $3.3 billion, with DOE contributing approximately $1.3 billion. In 2001, a solicitation for a follow-on to the original five rounds was issued. This program was called the Power Plant Improvement Initiative (PPII), and it resulted in six projects, of which four are finished, one is still active, and one was withdrawn. The total value of the five implemented PPII projects was approximately $71 million, with DOE contributing approximately $32 million.

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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-NO 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.

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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 predemonstration scale. It includes Advanced Research, Advanced Turbines, Carbon Sequestration, Fuel Cells, Gasification, Hydrogen and Fuels, and Innovations for Existing Plants, which are described in more detail below.

Advanced Research The Advanced Research Program is a bridge between basic research and the development and deployment of innovative systems capable of creating highly efficient and environmentally benign power- and energy-production systems. Research objectives include

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resolving the technology barriers that enable improvements to emerging power systems as well as fundamental research on novel technologies that can be utilized in clean energy production. The objective of the program is to support development of critical enabling technologies to make it possible for the line programs to achieve their goals of developing advanced, coal-based power systems for affordable, efficient, near-zero atmospheric emissions power generation. Example developments include high-temperature materials, revolutionary sensors and controls, and advanced computing/visualization techniques.

Advanced Turbines The Advanced Turbine Program consists of a portfolio of laboratory and field R&D projects focused on performance-improvement technologies with great potential for increasing efficiency and reducing emissions and costs in coal-based applications. The Program focuses on the combustion of pure hydrogen fuels in MW-scale turbines greater than 100 MW size range and the compression of large volumes of CO2. Since advanced turbines will be fuel flexible, capable of operating on hydrogen or syngas, they will make possible electric power generation in gasification applications configured to capture CO2.

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Carbon Sequestration The Carbon Sequestration Program consists of a portfolio of laboratory and field R&D focused on technologies with great potential for reducing greenhouse gas emissions. Most efforts focus on capturing carbon dioxide from large stationary sources such as power plants, and sequestering carbon dioxide in geologic formations. The Program also addresses the control of fugitive methane emissions, which is another potent greenhouse gas. Carbon sequestration is a key component of the President‘s strategy to slow the growth of greenhouse gas emissions, as well as several National Energy Policy goals targeting the development of new technologies. It also supports the goals of the Framework Convention on Climate Change and other international collaborations to reduce greenhouse gas intensity and greenhouse gas emissions. The programmatic timeline is to demonstrate a portfolio of safe, cost-effective greenhouse gas capture, storage, and mitigation technologies at the precommercial scale by 2012, leading to demonstration and substantial deployment and market penetration beyond 2012. These greenhouse gas mitigation technologies could help slow greenhouse gas emissions in the medium term. They also provide potential for ultimately stabilizing and reducing greenhouse gas emissions in the United States.

Fuel Cells Fuel cells could help support the efficiency and emission targets of future power plants, such as FutureGen. The 50% higher heating value target is challenging, and fuel cells can clearly facilitate achieving this target when used as the main power block, possibly in combination with a turbine. In order to ensure the ability to site future power plants in any

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state in the country, low emissions of criteria pollutants will be required. Fuel cell emissions are well below current and proposed environmental limits. Fuel cells could play a significant part in energy security. Their modular nature permits use in central or distributed generation with equal ease. Rapid response to emergent energy needs is enhanced by the modularity and fuel flexibility of fuel cells. The ultimate goal of the program is the development of low-cost large (>100 MW) fuel cell power systems that will produce affordable, efficient, and environmentally friendly electrical power from coal with greater than 50% higher heating value (HHV) efficiency, including integrated coal gasification and carbon dioxide separation processes and capture at least 90% of the CO2 emissions from the system. The cost goal for fuel cells in coal systems is to achieve a ten-fold reduction in the fuel cell system cost.

Futuregen FutureGen is a $1 billion Government-industry initiative to design, build, and operate an advanced, coal-based, Integrated Gasification Combined-Cycle (IGCC) power plant to:

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Co-produce electricity and hydrogen; Achieve near-zero atmospheric emissions, with geological sequestration of carbon dioxide; Demonstrate system integration of cutting edge technologies; and Chart a technological pathway toward an energy future in which near-zero atmospheric emissions clean coal power plants can be designed, built, and operated at a cost that is no more than 10% above the cost of non-sequestered systems. Coal continues to face environmental challenges relative to other energy sources. The near-zero atmospheric emissions concept spearheaded by FutureGen is vital to the future viability of coal as an energy resource, particularly in light of growing climate change concerns. Coal is abundant, secure, and relatively inexpensive when compared to other energy sources. With near-zero atmospheric emissions, coal could not only produce baseload electricity, but also help germinate a hydrogen energy economy.

Gasification Gasification is a pre-combustion pathway to convert coal or other carbon-containing feedstocks into synthesis gas, a mixture composed primarily of carbon monoxide and hydrogen; the synthesis gas, in turn, can be used as a fuel to generate electricity or steam, or as a basic raw material to produce hydrogen, high-value chemicals, and liquid transportation fuels. DOE isdeveloping advanced gasification technologies to meet the most stringent environmental regulations in any state and facilitate the efficient capture of CO2 for subsequent sequestration—a pathway to ―near-zero atmospheric emissions‖ coal-based energy. Gasification plants are complex systems that rely on a large number of interconnected processes and technologies. Advances in the current state-of-the-art, as well as development

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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.

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Innovations for Existing Plants Over the past three decades, the existing fleet of coal-fired power plants has made significant strides in reducing air emissions, minimizing impacts on water quality and availability, and managing solid byproducts. As the coal-based electric utility sector enters the 21st century, it will be faced with additional environmental issues such as mercury, nitrogen oxide, air toxics, and acid-gas emissions control requirements, constraints on water availability needed for plant cooling and other purposes, and decreasing space available to dispose of the solid residues from coal combustion. The Innovations for Existing Plants subprogram supported technology development in anticipation of regulatory limits that are now being implemented through the Clean Air Interstate Rule and the Clean Air Mercury Rule. These rules were promulgated in 2005, giving the private sector an incentive to develop the technologies required to reduce their pollutant emissions. Because the government role in development of these technologies has shifted to the private sector, the Innovations for Existing Plants subprogram is no longer needed.

Conclusion Today, nearly three out of every four coal-burning power plants in this country are equipped with technologies that can trace their roots back to the Clean Coal Technology Program. Approaches demonstrated through the program include coal processing to produce clean fuels, combustion modification to control emissions, post-combustion cleanup of flue gas, and repowering with advanced power generation systems. These efforts helped accelerate production of cost-effective compliance options to address environmental issues associated with coal use. Relative to carbon capture and storage, DOE is making significant progress in developing the technologies and infrastructure needed for deployment of these technologies in a future carbon-constrained world. The following are some examples of clean coal successes that were developed in part with DOE support:

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The current generation of low-NOX burners alone is a major clean coal success story. Nearly $1.5 billion of these burners have been sold. Selective catalytic reduction now costs half what it did in the 1980s and systems are on order or under construction for 30 percent of U.S. coal-fired plants. Flue gas scrubbers are a third of their cost in the 1970s, and they are more reliable, less costly and more efficient due to innovations developed and tested in Clean Coal Technology Program. Fluidized bed technology developed in the core coal R&D program and first demonstrated in the program has recorded global sales of over $10 billion. In Tampa, Florida, and West Terre Haute, Indiana, the first pioneering, full-size coal gasification power plants have opened a new pathway for the next generation of clean, fuel-flexible power plants. This was made possible through demonstration projects under the Clean Coal Technology Program. A number of the commercial demonstration projects have received technology achievement awards. These include the Tidd pressurized fluidized-bed combustion project by Ohio Power Company; Babcock & Wilcox Company low-NOx/cell burner project; Pure Air Lake‘s advanced flue gas desulfurization project; and Southern Company Services‘ CT-121 flue gas desulfurization project. Advanced coal preparation work previously conducted at NETL‘s onsite research facilities is now standard practice in the energy industry in achieving product quality specifications for sulfur emissions compliance, as well as reductions of other air pollutants including mercury and other trace elements. Work sponsored by the clean coal program continues to look at mercury and multipollutant controls for coal-fired boilers. Operation of the TOXECONTM process, which could offer coal-fired power plants a low-cost retrofit option for reducing mercury emissions by up to 90%, was initiated at the We Energies Presque Isle Power Plant in Marquette, Michigan. This project demonstrates the first full-scale commercial mercuryemission-control system for permanent operation. The Carbon Sequestration Atlas of the United States and Canada, developed by NETL, the Regional Carbon Sequestration Partnerships (Partnerships), and the National Carbon Sequestration Database and Geographical Information System, contains information on stationary sources for CO2 emissions, geologic formations with sequestration potential, and terrestrial ecosystems with potential for enhanced carbon uptake, all referenced to their geographic location to enable matching sources and sequestration sites. CO2 capture technology is being developed for solvent, sorbent, membrane, and oxycombustion systems that, if successfully developed, would be capable of capturing greater than 90 percent of the flue gas CO2 at a significant cost reduction when compared to state-of-the-art, amine-based capture systems. Research and systems analysis have identified potential cost reductions of 30-45% for the capture of CO2. In addition, ionic liquid membranes and absorbents are being developed for capture of CO2 from power plants. Ionic liquid membranes have been developed at NETL for pre-combustion applications that surpass polymers in terms of CO2 selectivity and permeability at elevated temperatures.

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United States Government Printing Office Field projects have demonstrated the ability to ―map‖ CO2 injected into an underground formation at a much higher resolution than previously anticipated and confirmed the ability of perfluorocarbon tracers to track CO2 movement through a reservoir. DOE-sponsored research has also led to the development of the U-Tube sampler, which was developed for and successfully deployed at the Frio test site in Texas. This novel tool is used to obtain geochemical samples of both the water and gas portions of downhole samples at in situ pressure. The Carbon Sequestration Regional Partnerships have brought an enormous amount of capability and experience together to work on the challenge of infrastructure development. Together with DOE, the Partnerships secured the active participation of more than 500 individuals representing more than 350 industrial companies, engineering firms, state agencies, non-governmental organizations, and other supporting organizations. The Partnerships are conducting field tests to validate the efficacy of carbon capture and storage technologies in a variety of geologic storage sites throughout the U.S. and Canada. Using the extensive data and information gathered during the initial stages of the project, the seven Partnerships identified the most promising opportunities for carbon sequestration in their Regions and are performing 25 geologic field tests.

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In conclusion, DOE‘s Clean Coal R&D Program has a successful track record and a promising future that will ultimately lead to coal plants with near-zero atmospheric emissions. Mr. Chairman, and Members of the Committee, this completes my statement. I would be happy to take any questions you may have at this time. The Chairman. OK, thank you very much. Mr. Hollinden, why don‘t you go right ahead, please.

STATEMENT OF JERRY HOLLINDEN, REPRESENTATIVE, THE NATIONAL COAL COUNCIL Mr. Hollinden. Good morning, Mr. Chairman. My name is Jerry Hollinden and today I‘m testifying on behalf of the National Coal Council. The Council is a Federal Advisory Committee to the Secretary of Energy. Council membership is by personal appointment of the Secretary and included representatives from across the broad spectrum of the coal and energy industry. All members volunteer their time and expertise to the Secretary on issues that he requests the Council to address. By letter dated June 26, 2006, Secretary Bodman requested that the Council conduct a study of technologies available to avoid or capture and store carbon dioxide emissions, especially those from coal-fired power plants. Additionally the Secretary requested that the Council recommend a technology-base framework for mitigating green house gas emissions from those plants. The Council accepted the Secretary‘s request, formulated a work- group of about 45 experts in the field, and on June 7 of this year submitted their report to Secretary Bodman.

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Today, I will summarize the key findings and recommendations of that study and I have attached a copy of the full report to my testimony for the record. The report includes four major findings. One, coal must continue its vital and growing role in energy production in the United States, supplying more than 50 percent of the Nation‘s electricity. Two, reducing carbon dioxide emissions presents a significant technological challenge, but the coal industry has a proven record of successfully meeting such challenges and stands ready to meet this one as well. Three, it is imperative that research, development, and demonstration efforts move forward quickly on a portfolio of technologies to reduce our capture and store carbon dioxide emissions. Four, public/private support for technologies to reduce our capture and store carbon dioxide is critical to the energy independence and security of the United States. As indicated by today‘s hearings, the Council understands that Congress intends to address carbon management. In that context, it is imperative that the Nation immediately accelerate deployment of technologically and economically favorable high-efficiency advanced coal combustion, coal liquefaction, and gasification technologies. In addition, it is critical to accelerate development, demonstration, and deployment of carbon dioxide reduction and carbon capture and storage technologies to control and sequester carbon dioxide emissions from these advanced coal-based technologies. With this in mind, the Council made the following recommendations to Secretary Bodman. One, work closely with other appropriate agencies within the Federal Government to streamline—not eliminate as some have accused the Council of recommending—but streamlining the long, costly, and complicated permitting process for siting, building, and operating coal power plants and associated carbon dioxide capture, storage, and facilities. Two, significantly increase funding across the full spectrum of carbon capture and storage technologies, including the capture, compression, transportation, storage, and monitoring, so as to ensure that the expectations for carbon dioxide capture and storage will be met on the local, State, and national levels. Three, determine the legal liabilities associated with carbon capture and storage. Four, increase funding of the regional carbon sequestration partnerships to adequately finance large- scale carbon dioxide storage projects in a number of different geological formations, such as deep saline reservoirs. Five, support research projects that cover a wide variety of capture technologies, including those that capture less than 90 percent of emissions, because they are in the early stages of a technology maturation process. Six, pursue a large-scale demonstration project to spur development of ultra-supercritical pulverized coal technology for electricity generation. Seven, ensure Integrated Gasification Combined Cycle technology has been completely and efficiently integrated into a large-scale power plant and carbon capture and storage system. As I stated earlier, the Secretary also asked the Council to recommend a framework for doing this. To do this, necessary actions would be. In the near-term, efficiency improvements at existing power plants should be expedited. For the mid-term, advanced clean coal technology, such as IGCC and ultra-supercritical combustion, must be given public support in the form of cost and permitting incentives and financial support for initial demonstrations so that they can succeed in the marketplace. In the long-term, technology for carbon capture and

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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:]

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Prepared Statement of Jerry Hollinden, Representative, the National Coal Council Good morning, Mr. Chairman. My name is Jerry Hollinden and today I am testifying on behalf of The National Coal Council. The Council is a federal advisory committee to the Secretary of Energy. Council membership is by personal appointment of the Secretary and includes representatives from across the broad spectrum of the coal and energy industry. Council members include senior executives from coal producers, shippers and users as well as consultants, conservation groups, Native Americans, university faculty members, State government officials, lawyers, boiler manufacturers, architect/engineers and large electricity consumers. All members volunteer their time and expertise to the Secretary on issues that he requests the Council to address. By letter dated June 26, 2006 Secretary Samuel Bodman requested that the Council ―conduct a study of technologies available to avoid, or capture and store, carbon dioxide emissions—especially those from coal-fired power plants.‖ Additionally, the Secretary requested that the Council recommend ―a technology-based framework for mitigating greenhouse gas emissions from those plants.‖ The Council accepted the Secretary‘s request, formulated a working group of about 45 experts in the field, and on June 7, 2007 submitted their report to Secretary Bodman. Today I will summarize the key findings and recommendations of that study, and I have attached a copy of the full report* to my testimony for the record. The report includes four major findings: 1. Coal must continue its vital and growing role in energy production in the United States, supplying more than 50 percent of the nation‘s electricity. 2. Reducing carbon dioxide emissions presents a significant technological challenge, but the coal industry has a proven record of successfully meeting such challenges and stands ready to meet this one as well. 3. It is imperative that research, development and demonstration efforts move forward quickly on a portfolio of technologies to reduce or capture and store carbon dioxide emissions. 4. Public-private support for technologies to reduce or capture and store carbon dioxide is critical to the energy independence and security of the United States. As indicated by today‘s hearing, the Council understands that Congress intends to address carbon management. In that context, it is imperative that the nation immediately accelerate deployment of technologically and economically favorable high-efficiency advanced coal combustion, coal liquefaction and gasification technologies. In addition, it is

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

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United States Government Printing Office 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, onitoring and closure of storage facilities. c. Ensuring creation of a federal entity to take title to, and responsibility for, long-term post-closure monitoring of underground storage, liability and remediation at all carbon dioxide management sites. d. Facilitating development of an economic, efficient and adequate infrastructure for transportation and storage of captured carbon dioxide. e. Creating a legal framework to indemnify all entities that safely capture, transport and store carbon dioxide. f. Creating clear transportation and storage rules that provide incentives to business models that will encourage the development of independent collection pipelines and storage facilities.

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10. Consider undertaking 3-5 projects at a scale of about 1 million tons per year of carbon dioxide injection to understand the outstanding technical challenges and to demonstrate to the public that long-term carbon dioxide storage can be achieved safely and effectively. As I stated earlier, the Secretary also asked the Council to recommend a framework for mitigating greenhouse gas emissions from coal-based generating plants. This framework is simple conceptually but difficult in terms of marshalling the requisite financial commitments, resolving legal and regulatory uncertainties, and instituting appropriate risk-sharing mechanisms. Necessary actions include: Near Term.—Efficiency improvements at existing plants should be expedited. This can be achieved both technically and economically, but regulatory barriers must be addressed including the New Source Review process. In such cases, New Source Review should not be required for plant efficiency improvements that reduce carbon dioxide emissions with no subsequent increase in sulfur dioxide or oxides of nitrogen emissions increases. Mid Term.—Advanced clean coal technologies such as IGCC and ultra-supercritical combustion must be given public policy support in the form of cost and permitting incentives and financial support for initial demonstrations so they can succeed in the marketplace. Legal questions about liability for long term storage must be addressed. Continued progress on FutureGen will be very important in these matters. Long Term.—Technology for carbon capture and storage, including storage sites and related infrastructure, must be developed and demonstrated over the next 10 years. Several major carbon capture and storage projects must be started as soon as possible in order to achieve commercialization within the next 15 years. Oxygen firing technologies are designed specifically for carbon capture and will not develop independently of storage and infrastructure.

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

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STATEMENT OF JEFFREY N. PHILLIPS, PROGRAM MANAGER, ADVANCED COAL GENERATION, ELECTRIC POWER RESEARCH INSTITUTE, CHARLOTTE, NC Mr. Phillips. Mr. Chairman, I‘d like to thank you and your colleagues for inviting me to speak to you on behalf of our institute. As you can imagine, it‘s a little difficult to cover all the contents of our report in 5 minutes. So I just want to give you the highlights, which are, we have some good news and some bad news. We also have some more good news and some more bad news, and we have some additional bad news. So, if you‘re keeping track, it‘s two good and three bad. But the game is not over yet, and with a concerted public/private partnership, we believe that the outcome for coal and the carbon-constrained future can still be positive. Now, the first good news is that any new coal plant built today has the capability to achieve extremely low emissions of the so-called criteria pollutants—NOX, SOS, and so forth—while also operating at a significantly higher efficiencies than the existing coal plants in the United States. Now, most of the coal plants we have here were built in the 1950s, 1960s, and 1970s and a lot of folks think that coal power is old technology and can‘t be improved. We‘ve been building automobiles since the early 1900s and automotive technology is still improving. Similarly, today‘s new coal plants are as different from those built 30 years ago as 2007 electric hybrid car is from a 1975 AMC Pacer. I would have said Gremlin, which is what I grew up with, but I think Pacer is more humorous. While the higher efficiency of today‘s new plants means that they will produce less CO2 per megawatt-hour than the existing fleet, our analysis of the electric power sector shows that in order to get the sector CO2 emissions back down to 1990 levels by 2030, it‘s going to take more than just building more efficient coal plants. That‘s where my first bad news comes in. While several technologies that can capture CO2 emissions from coal power plants are ready to be demonstrated today, our analysis shows that they will significantly increase the cost of electricity. Capturing 90 percent of the CO2 from either a pulverized coal, or an IGCC power plant increases the cost of power by up to 80 percent.

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So adding CO2 capture would greatly increase the operating cost of a plant well above that of one that doesn‘t capture CO2. This means that a plant with CO2 capture will fall down the dispatch order and it will reduce the amount of time that that plant is called on to operate and consequently, it will reduce the amount of CO2 that‘s actually captured. So some means to induce CO2 capture without economically penalizing the owner of the power plant needs to be devised. If not, CO2 capture technology of any type will not be fully utilized. My other good news is, that while the impact of capturing CO2 today is significant, we have identified R&D pathways for both pulverized coal and IGCC that could dramatically reduce the cost of CO2 capture. The Joint Kirk-EPRI Roadmap issued last year, shows that with appropriate R&D and demonstrations, technology for CO2 capturing coal plants built in 2025 could lead to only a 10 percent increase in the cost of electricity. The other bad news is, that at current levels of funding for coal R&D, we‘ll never get there by 2025. In fact, we might not even get there by 2045. Getting a broad portfolio of costeffective capture technologies will require substantially increased—although not unprecedented—investments in R&D from both government and industry, on an unwavering basis over the next 20 plus years. Now toward this end, EPRI is now developing and marshalling support for an ambitious set of industry-led projects to address the R&D challenge. Now, I want to emphasize that whenever you try out new technologies, you‘re bound to run into glitches and reliability is going to suffer. Consequently, we recommend following a ―walk before you run‖ strategy, which means we‘ll try out these systems on a few plants, perhaps not at full scale to limit the cost. Let us fall on our bottoms a few times, dust ourselves off, figure out what went wrong, get the kinks out, before we start widespread deployment. My final bad news is that even if we were able to drive the cost of capturing CO2 to zero tomorrow, it‘s highly unlikely that any power plant owner will inject CO2 into deep reservoirs given the current uncertainty over the regulations and liability of deep geologic storage of CO2. Now, I‘m confident that our nation‘s engineers and scientists can solve the challenge of capturing CO2 at economically acceptable costs, but we need help from you on the legal issues. So in summary, today‘s new coal power plants are cleaner and more efficient than the existing fleet. Today‘s CO2 capture technology will increase wholesale electricity prices by up to 80 percent, but we‘ve identified a clear technology pathway that could decrease that to only 10 percent by 2025. Unfortunately, the funding for the development of that path is sadly inadequate. Finally, we engineers need some legal experts to help us sort out the rules for deep geologic storage of CO2. Thank you and I‘ll be happy to take your questions. [The prepared statement of Mr. Phillips follows:]

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Prepared Statement of Jeffrey N. Phillips, Ph.D., Program Manager, Advanced Coal Generation, Electric Power Research Institute, Charlotte, NC Introduction I am Jeff Phillips, Program Manager for Advanced Coal Generation for the Electric Power Research Institute (EPRI). EPRI is a non-profit, collaborative R&D organization with principal offices in Palo Alto, California, and Charlotte, North Carolina, where I work. EPRI appreciates the opportunity to provide testimony to the Subcommittee on the topic of carbon capture and sequestration.

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Background Coal is the energy source for half of the electricity generated in the United States. Even with the aggressive development and deployment of alternative energy sources, numerous forecasts of energy use predict that coal will continue to provide a major share of our electric power generation throughout the 21st century. Coal is a stably priced, affordable, domestic fuel that can be used in an environmentally responsible manner. Criteria air pollutants from all types of new coal power plants have been reduced by more than 90% compared with plants built 40 years ago. With the development and deployment of CO2 capture and storage (CCS) technologies, coal power becomes part of the solution to satisfying both our energy needs and our global climate change concerns. However, a sustained RD&D program at heightened levels of investment and resolution of legal and regulatory unknowns for longterm 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 selfsustaining, 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

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advantages across the range of U.S. applications. The best strategy for meeting future electricity needs while addressing climate change concerns and minimizing economic disruption lies in developing multiple technologies from which power producers (and their regulators) can choose the option best suited to local conditions and preferences. When it comes to CCS technology, there is no ―silver bullet,‖ but we can develop ―silver buckshot.‖ Toward this end, four major technology efforts related to CO2 emissions reduction from coal-based power systems must be undertaken: 1. Increased efficiency and reliability of integrated gasification combined cycle (IGCC) power plants. 2. Increased thermodynamic efficiency of pulverized-coal (PC) power plants. 3. Improved technologies for capture of CO2 from coal combustion-and gasificationbased power plants. 4. Reliable, acceptable technologies for long-term storage of captured. CO2 Identification of mechanisms to share RD&D financial and technical risks and to address legal and regulatory uncertainties must take place as well. In short, a comprehensive recognition of all the factors needed to hasten deployment of competitive, commercial advanced coal and CO2 capture and storage technologies—and implementation of realistic, pragmatic plans to overcome barriers— is the key to meeting the challenge to supply affordable, environmentally responsible energy in a carbon-constrained world.

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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

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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. 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.

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Reducing CO2 Emissions Through Improved Coal Power Plant Efficiency Improved thermodynamic efficiency reduces CO2 emissions by reducing the amount of fuel required to generate a given amount of electricity. A two-percentage point gain in efficiency provides a reduction in fuel consumption of roughly 5% and a similar reduction in CO2 output. Depending on the technology used, improved efficiency can also provide similar reductions in criteria air pollutants, hazardous air pollutants, and water consumption. A ―typical‖ 500 MW (net) coal plant emits about 3 million metric tons of CO2 per year. The annual power output and emissions of the current U.S. coal fleet are roughly equivalent to 600 such plants. The contributions attributable to individual plants vary considerably with differences in plant steam cycle, coal type, capacity factor, and operating regimes. For a given fuel, a new supercritical PC unit built today might produce 5–10% less CO2 per megawatthour (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

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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 efficiencybased 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 EPRICURC 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.

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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 ―FBclass‖ 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 energyefficient 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.

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Clean Coal Technology Hearing Table 1. Efficiency Milestones in EPRI-CURC Roadmap

PC & IGCC Systems (Without CO2 Capture)

2010

2015

2020

2025

38–41% HHV

39–43% HHV

42–46% HHV

44–49% HHV

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PC & IGCC Systems (With CO2 31–32% 31–35% 33–39% 39–46% Capture*) HHV HHV HHV HHV * Efficiency values reflect impact of 90% CO2 capture, but not compression or transportation.

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 onsite 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 nonoxygen atoms. According to developers, an ITM-based oxygen plant consumes 35–60% less power and costs 35% less than a cryogenic plant. EPRI is performing a due diligence assessment of this technology in advance of potential participation in technology scale-up efforts. Supercritical Heat Recovery Steam Generators.—In IGCC plants, hot exhaust gas exiting the gas turbine is ducted into a heat exchanger known as a heat recovery steam generator (HRSG) to transfer energy into water-filled tubes producing steam to drive a steam turbine. This combination of a gas turbine and steam turbine power cycles produces electricity more efficiently than either a gas turbine or steam turbine alone. As with conventional steam power plants, the efficiency of the steam cycle in a combined cycle plant increases when turbine inlet steam temperature and pressure are increased. The higher exhaust temperatures of G-and H-class gas turbines offer the potential for adoption of more-efficient supercritical steam cycles. Materials for use in a supercritical HRSG are generally established. Synthesis Gas Cleaning at Higher Temperatures.—The acid gas recovery (AGR) processes currently used to remove sulfur compounds from synthesis gas require that the gas and solvent be cooled to about 100°F, thereby causing a loss in efficiency. Further costs and efficiency loss are inherent in the process equipment and auxiliary steam required to recover the sulfur compounds from the solvent and convert them to useable products. Several DOEsponsored RD&D efforts aim to reduce the energy losses and costs imposed by this recovery process. These technologies (described below could be ready—with adequate RD&D support—by 2020: The Selective Catalytic Oxidation of Hydrogen Sulfide process eliminates the Claus and Tail Gas Treating units along with the traditional solvent-based AGR contactor, regenerator, and heat exchangers by directly converting hydrogen sulfide (H2S) to elemental sulfur. The process allows for a higher operating temperature of approximately 300°F, which eliminates part of the low-temperature gas cooling train.

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The anticipated benefit is a net capital cost reduction of about $60/kW along with an efficiency gain of about 0.8 percentage point. The RTI/Eastman High Temperature Desulfurization System uses a regenerable dry zinc oxide sorbent in a dual loop transport reactor system to convert H2S and COS to H2O, CO2, and SO2. Tests at Eastman Chemical Company have shown sulfur species removal rates above 99.9%, with 10 ppm output versus 8000 ∂ ppm input sulfur, using operating temperatures of 800–1000°F. This process is also being tested for its ability to provide a high-pressure CO2 byproduct. 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 480°F. Liquid CO2-Coal Slurrying for Gasification of Low-Rank Coals.—Future IGCC plants may recycle some of the recovered liquid CO2 to replace water as the slurrying medium for the coal feed. This is expected to increase gasification efficiency for all coals, but particularly for low-rank coals (i.e., subbituminous and lignite), which have high inherent moisture content. The liquid CO2 has a lower heat of vaporization than water and is able to carry more coal per unit mass of fluid. The liquid CO2-coal slurry will flash almost immediately upon entering the gasifier, providing good dispersion of the coal particles and potentially yielding dry-fed gasifier performance with slurry-fed simplicity. Slurry-fed gasification technologies have a cost advantage over conventional dry- fed fuel handling systems, but they suffer a large performance penalty when used with coals containing a large fraction of water and ash. EPRI identified CO2 coal slurrying as an innovative fuel preparation concept 20 years ago, when IGCC technology was in its infancy. At that time, however, the cost of producing liquid CO2 was too high to justify the improved thermodynamic performance. To date, CO2-coal slurrying has only been demonstrated at pilot scale and has yet to be assessed in feeding coal to a gasifier, so the estimated performance benefits remain to be confirmed. The concept warrants consideration for future IGCC plants that capture and compress CO2 for storage, as this will substantially reduce the incremental cost of producing a liquid CO2 stream. It will first be necessary, however, to update previous studies to quantify the potential benefit of liquid CO2 slurries with IGCC plants designed for CO2 capture. If the predicted benefit is economically advantageous, a significant amount of scale-up and demonstration work would be required to qualify this technology for commercial use. Fuel Cells and IGCC.—No matter how far gasification and turbine technology advance, IGCC power plant efficiency will never progress beyond the inherent thermodynamic limits of the gas turbine and steam turbine power cycles (along with lower limits imposed by available materials technology). Several IGCC–fuel cell hybrid power plant concepts (IGFC) aim to provide a path to coal-based power generation with net efficiencies that exceed those of conventional combined cycle generation. Along with its high thermal efficiency, the fuel cell hybrid cycle reduces the energy consumption for CO2 capture. The anode section of the fuel cell produces a stream that is highly concentrated in CO2. After removal of water, this stream can be compressed for sequestration. The concentrated CO2 stream is produced without having to include a water-

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gas shift reactor in the process (see Figure 4*). This further improves the thermal efficiency and decreases capital cost. IGFC power systems are a long-term solution, however, unlikely to see full-scale demonstration until about 2030. Role of FutureGen.—The FutureGen Industrial Alliance and DOE are building a first-ofits-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 fullscale and slipstream tests of such scalable advanced technologies such as:

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Membrane processes to replace cryogenic separation for oxygen production. An advanced transport reactor sidestream with 30% of the capacity of the main gasifier. Advanced membrane and solvent processes for H2 and CO2 separation. A raw gas shift reactor that reduces the upstream clean-up requirements. Ultra low-NOX combustors that can be used with high-hydrogen synthesis gas. A fuel cell hybrid combined cycle pilot. Challenging first-of-a-kind system integration. Smart dynamic plant controls including a CO2 management system. Figure 5** provides a schematic of the ―backbone‖ and ―research platform‖ process trains envisioned for the FutureGen plant. Figure 6** summarizes EPRI‘s recommended major RD&D activities for improving the efficiency and cost of IGCC technologies with CO2 capture.

New Plant Efficiency Improvements—Advanced Pulverized Coal Pulverized-coal power plants have long been a primary source of reliable and affordable power in the United States and around the world. The advanced level of maturity of the technology, along with basic thermodynamic principles, suggests that significant efficiency gains can most readily be realized by increasing the operating temperatures and pressures of the steam cycle. Such increases, in turn, can be achieved only if there is adequate development of suitable materials and new boiler and steam turbine designs that allow use of higher steam temperatures and pressures. Current state-of-the-art plants use supercritical main steam conditions (i.e., temperature and pressure above the ―critical point‖ where the liquid and vapor phases of water are indistinguishable). SCPC plants typically have main steam conditions up to 1100°F. The term ―ultra-supercritical‖ is used to describe plants with main steam temperatures in excess of 1100°F and potentially as high as 1400°F.

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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 1300°F will be built during the next seven to ten years, following the demonstration and commercial availability of advanced materials from these programs. This plant would achieve an efficiency of about 45% (HHV) on bituminous coal, compared with 39% for a current state- of-the-art plant, and would reduce CO2 production per net MWh by about 15%. Ultimately, nickel-base alloys are expected to enable stream temperatures in the neighborhood of 1400°F and generating efficiencies up to 47% HHV with bituminous coal. This approximately 10 percentage point improvement over the efficiency of a new subcritical pulverized-coal plant would equate to a decrease of about 25% in CO2 and other emissions per MWh. Figure 7** illustrates a timeline developed by EPRI‘s CoalFleet for Tomorrow® program to establish efficiency improvement and cost reduction goals for USC PC plants with CO2 capture. UltraGen USC PC Commercial Projects.—EPRI and industry representatives have proposed a framework to support commercial projects that demonstrate advanced PC technologies. The vision entails construction of two commercially operated USC PC power plants that combine state-of-the-art pollution controls, ultra-supercritical steam power cycles, and innovative flue gas scrubbing technologies to capture CO2. The UltraGen I plant will use the best of today‘s proven ferritic steels, while UltraGen II will be the first plant in the United States to feature new, nickel-based alloys that are able to withstand the higher temperatures involved. UltraGen I will feature an approximately quarterscale 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 industryled consortia formed through EPRI. The UltraGen projects represent the type of ―giant step‖ collaborative efforts that need to be taken to advance PC technology to the next phase of evolution and assure competitiveness in a carbon-constrained world. Because of the time and expense for each ―design and build‖ iteration for coal power plants (3 to 5 years not counting the permitting process and ~$2

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billion), there is no room for hesitation in terms of commitment to advanced technology validation and demonstration projects. The UltraGen projects will resolve critical barriers to the deployment of USC PC technology by providing a shared-risk vehicle for testing and validating high-temperature materials, components, and designs in plants also providing superior environmental performance. Figure 9** summarizes EPRI‘s recommended major RD&D activities for improving the efficiency and cost of USC PC technologies with CO2 capture. Efficiency Gains for the Existing PC Fleet.—Many subcritical units in the existing U.S. fleet will continue to operate for years to come. Replacing these units en masse would be economically prohibitive. Their flexibility for load following and provision of support services to ensure grid stability makes them highly valuable. With equipment upgrades, many of these units can realize modest efficiency gains, which, when accumulated across the existing generating fleet could make a sizeable difference. These upgrades depend on the equipment configuration and operating parameters of a particular plant and may include: turbine blading and steam path upgrades. turbine control valve upgrades for more efficient regulation of steam. cooling tower and condenser upgrades to reduce circulating water temperature, steam turbine exhaust backpressure, and auxiliary power consumption. cooling tower heat transfer media upgrades. condenser optimization to maximize heat transfer and minimize condenser temperature. condenser air leakage prevention/detection. variable speed drive technology for pump and fan motors to reduce power consumption. air heater upgrades to increase heat recovery and reduce leakage. advanced control systems incorporating neural nets to optimize temperature, pressure, and flow rates of fuel, air, flue gas, steam, and water. optimization of water blowdown and blowdown energy recovery. optimization of attemperator design, control, and operating scenarios. sootblower optimization via ―intelligent‖ sootblower system use.

Improving CO2 Capture Technologies The laws of physics and chemistry impose inherent limits on the extent of CO2 reductions that can be achieved through efficiency gains alone. Further reductions in CO2 emissions will require pre-combustion or post-combustion CO2 capture technologies and the storage of separated CO2 in locations where it can be kept away from the atmosphere for centuries or longer. Albeit at considerable cost, CO2 capture technologies can be integrated into all coalbased power plant technologies. For existing plants, specific plant design features, space limitations, and various economic and regulatory considerations will determine whether

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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-ofelectricity 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.

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Pre-Combustion CO2 Capture (IGCC) IGCC technology allows for CO2 capture to take place via an added fuel gas processing step at elevated pressure, rather than at the atmospheric pressure of post- combustion flue gas, permitting capital savings through smaller equipment sizes as well as lower operating costs. Currently available technologies for such pre-combustion CO2 removal use a chemical and/or physical solvent that selectively absorbs CO2 and other ―acid gases,‖ such as hydrogen sulfide. Application of this technology requires that the CO in synthesis gas (the principal component) first be ―shifted‖ to CO2 and hydrogen via a catalytic reaction with water. The CO2 in the shifted synthesis gas is then removed via contact with the solvent in an absorber column, leaving a hydrogen-rich synthesis gas for combustion in the gas turbine. The CO2 is released from the solvent in a regeneration process that typically reduces pressure and/or increases temperature. Chemical plants currently employ such a process commercially using methyl diethanolamine (MDEA) as a chemical solvent or the Selexol and Rectisol processes, which rely on physical solvents. Physical solvents are generally preferred when extremely high (>99.8%) sulfur species removal is required. Although the required scale-up for IGCC power plant applications is less than that needed for scale-up of post-combustion CO2 capture processes for PC plants, considerable engineering challenges remain and work on optimal integration with IGCC cycle processes has just begun. The impact of current pre-combustion CO2 removal processes on IGCC plant thermal efficiency and capital cost is significant. In particular, the water-gas shift reaction reduces the heating value of synthesis gas fed to the gas turbine. Because the gasifier outlet ratios of CO to methane to H2 are different for each gasifier technology, the relative impact of the watergas 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 repressurized 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

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cycle processes to minimize these energy impacts is complex and is currently the subject of considerable RD&D by EPRI and others. Membrane CO2 Separation.—Technology for separating CO2 from shifted synthesis gas (or flue gas from PC plants) offers the promise of lower auxiliary power consumption but is currently only at the laboratory stage of development. Several organizations are pursuing different approaches to membrane-based applications. In general, however, CO2 recovery on the low-pressure side of a selective membrane can take place at a higher pressure than is now possible with solvent processes, reducing the subsequent power demand for compressing CO2 to a supercritical state. Membrane-based processes can also eliminate steam and power consumption for regenerating and pumping solvent, respectively, but they require power to create the pressure difference between the source gas and CO2-rich sides. If membrane technology can be developed at scale to meet performance goals, it could enable up to a 50% reduction in capital cost and auxiliary power requirements relative to current CO2 capture and compression technology.

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Post-Combustion CO2 Capture (PC and CFB Plants) The post-combustion CO2 capture processes envisioned for power plant boilers draw upon commercial experience with amine solvent separation at much smaller scale in the food and beverage and chemical industries and upon three applications of CO2 capture from a slipstream of exhaust gas from circulating fluidized-bed (CFB) units. These processes contact flue gas with an amine solvent in an absorber column (much like a wet SO2 scrubber) where the CO2 chemically reacts with the solvent. The CO2-rich liquid mixture then passes to a stripper column where it is heated to change the chemical equilibrium point, releasing the CO2. The ―regenerated‖ solvent is then recirculated back to the absorber column, while the released CO2 may be further processed before compression to a supercritical state for efficient transportation to a storage location. After drying, the CO2 released from the regenerator is relatively pure. However, success CO2 removal requires very low levels of SO2 and NO2 entering the CO2 absorber, as these species also react with the solvent. Thus, high-efficiency SO2 and NOX control systems are essential to minimizing solvent consumption costs for post- combustion CO2 capture. Extensive RD&D is in progress to improve the solvent and system designs for power boiler applications and to develop better solvents with greater absorption capacity, less energy demand for regeneration, and greater ability to accommodate flue gas contaminants. At present, monoethanolamine (MEA) is the ―default‖ solvent for post-combustion CO2 capture studies and small-scale field applications. Processes based on improved amines, such as Fluor‘s Econamine FG Plus and Mitsubishi Heavy Industries‘ KS– 1, are under development. The potential for improving amine-based processes appears significant. For example, a recent study based on KS–1 suggests that its impact on net power output for a supercritical PC unit would be 19% and its impact on the levelized cost-of-electricity would be 44%, whereas earlier studies based on suboptimal MEA applications yielded output penalties approaching 30% and costof-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

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with modifications to the chemical properties of the sorbents, these efforts are addressing the physical structure of the absorber and regenerator equipment, examining membrane contactors and other modifications to improve gas-liquid contact and/or heat transfer, and optimizing thermal integration with steam turbine and balance-of-plant systems. Although the challenge is daunting, the payoff is potentially massive, as these solutions may be applicable not only to new plants, but to retrofits where sufficient plot space is available at the back end of the plant. Finally, as discussed earlier, deploying USC PC technology to increase efficiency and lower uncontrolled CO2 per MWh can further reduce the cost impact of post- combustion CO2 capture. Chilled Ammonia Process.—Post-combustion CO2 capture using a chilled ammoniabased 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 costof-electricity penalty of just 25%. Following successful experiments at 0.25 MWe scale, Alstom and a consortium of EPRI members are constructing a 1.7 MWe pilot unit to test the chilled ammonia process with a flue gas slipstream at We Energies‘ Pleasant Prairie Power Plant. Other ―multi-pollutant‖ control system developers are also exploring ammonia- based processes for CO2 removal.

Oxy-Fuel Combustion Boilers Fuel combustion in a blend of oxygen and recycled flue gas rather than in air (known as oxy-fuel combustion or oxy-combustion) is gaining interest as a viable CO2 capture alternative for PC and CFB plants. The process is applicable to virtually all fossil-fueled boiler types and is a candidate for retrofits as well as new power plants. Firing coal only with high-purity oxygen would result in too high of a flame temperature, which would increase slagging, fouling, and corrosion problems, so the oxygen is diluted by mixing it with a slipstream of recycled flue gas. As a result, the flue gas downstream of the recycle slipstream take-off consists primarily of CO2 and water vapor (although it also contains small amounts of nitrogen, oxygen, and criteria pollutants). After the water is condensed, the CO2-rich gas is compressed and purified to remove contaminants and prepare the CO2 for transportation and storage. Oxy-combustion boilers have been studied in laboratory-scale and small pilot units of up to 3 MWt. Two larger pilot units, at ~10 MWe, are now under construction by Babcock & Wilcox (B&W) and Vattenfall. An Australian-Japanese project team is pursuing a 30 MWe

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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.

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CO2 Transport and Geologic Storage Application of CO2 capture technologies implies that there will be secure and economical storage or beneficial uses that can assure CO2 will be kept out of the atmosphere. The most developed approach for large-scale CO2 storage is injection into deep, well-sealed geological formations, including depleted or partially depleted oil and gas reservoirs and similar geologically sealed ―saline formations‖ (porous rocks filled with brine that is impractical for desalination). Partially depleted oil reservoirs provide the added benefit of enhanced oil recovery (EOR). [EOR is used in mature fields to recover additional oil after standard extraction methods have been used. When CO2 is injected for EOR, it causes residual oil to swell and become less viscous, allowing some to flow to production wells, thus extending the field‘s productive life.] Although EOR can help the economics of CCS projects, EOR sites are ultimately too few and too geographically isolated to accommodate much of the CO2 from large-scale industrial CO2 capture operations. In contrast, saline formations are available in many—but not all—U.S. locations. Natural underground CO2 reservoirs in Colorado, Utah, and other western states testify to the effectiveness of long-term geologic CO2 storage. CO2 is also found in natural gas reservoirs, where it has resided for millions of years. Thus, evidence suggests that depleted or near-depleted oil and gas reservoirs, and similarly ―capped‖ saline formations will be ideal for storing CO2 for millennia or longer. Geologic sequestration as a strategy for reducing CO2 emissions from the atmosphere is currently being demonstrated in several projects around the world. Three larger-scale projects—Statoil‘s Sleipner Saline Aquifer CO2 Storage project in the North Sea off of Norway; the Weyburn Project in Saskatchewan, Canada; and the In Salah Project in Algeria—together sequester about 3–4 million metric tons of CO2 per year, which collectively approaches the output of just one typical 500 MW coal-fired power plant. With 17 collective operating years of experience, these projects have thus far demonstrated that CO2 storage in deep geologic formations can be carried out safely and reliably. Statoil estimates that Norwegian greenhouse gas emissions would have risen incrementally by 3% if the CO2 from the Sleipner project had been vented rather than sequestered.2 Table 2 lists a selection of current and planned CO2 storage projects as of early 2007, including those involving EOR. 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.

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PROJECT

CO2 SOURCE

COUNTRY

START

Anticipated amount injected by: 2006 2010 2015 9 MT 13 MT 18 MT 5 MT 12 MT 17 MT 2 MT 7 MT 12 MT 0 2 MT 5 MT 0 0 12 MT 0 1 MT 8 MT 0 0 16 MT 0 0 7 MT 0 0 2 MT 0 0 NA 0 0 NA

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Sleipner Gas. Proc. Norway 1996 Weyburn Coal Canada 2000 In Salah Gas. Proc. Algeria 2004 Snohvit Gas. Proc. Norway 2007 Gorgon Gas. Proc. Australia 2010 DF-1 Miller Gas U.K. 2009 DF-2 Carson Pet Coke U.S. 2011 Draugen Gas Norway 2012 FutureGen Coal U.S. 2012 Monash Coal Australia NA SaskPower Coal Canada NA Ketzin/CO2 NA Germany 2007 0 50 KT 50 KT STORE 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 CoalFired 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.]

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 WeyburnMidale CO2 monitoring projects in Saskatchewan, Canada. The Weyburn project uses captured and dried CO2 from the Dakota Gasification Company‘s Great Plains synfuels plant near Beulah, North Dakota. The CO2 is transported via a 200 mile pipeline constructed of standard carbon steel. Over the life of the project, the net CO2 storage is estimated at 20 million metric tons, while an additional 130 million barrels of oil will be produced. The economic value of EOR with CCS represents an excellent opportunity for initial geologic sequestration projects like Weyburn. In addition, ―next generation‖ CO2-EOR processes could boost U.S. technically recoverable oil resources by 160 billion barrels.3

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.

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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 longterm storage, will use CO2 compressed for volumetric efficiency to a liquid-like ―supercritical‖ state; thus, virtually all CO2 storage will take place in formations at least a half-mile deep, where the risk of leakage to shallower groundwater aquifers or to the surface is less likely to occur. After successful completion of pilot-scale CO2 storage validation tests, the Partnerships will undertake large-volume storage tests, injecting quantities of ∼ 1 million metric tons of CO2 or more over a several year period, along with post-injection monitoring to track the absorption of the CO2 in the target formation(s) and to check for potential leakage. The EPRI–CURC Roadmap identifies the need for several large-scale integrated demonstrations of CO2 capture and storage. This assessment was echoed by MIT in its recent Future of Coal report, which calls for three to five U.S. demonstrations of about 1 million metric tons of CO2 per year and about 10 worldwide.4 These demonstrations could be the critical path item in commercialization of CCS technology. In addition, EPRI has identified 10 key topics where further technical and/or policy development is needed before CCS can become fully commercial: Caprock integrity Injectivity and storage capacity CO2 trapping mechanisms CO2 leakage and permanence CO2 and mineral interactions Reliable, low-cost monitoring systems Quick response and mitigation and remediation procedures Protection of potable water Mineral rights Long-term liability Figure 12** summarizes the relationship between EPRI‘s recommended large-scale integrated CO2 capture and storage demonstrations and the Regional Partnerships‘ ―Phase III‖ large-volume CO2 storage tests.

CO2 Transportation Mapping of the distribution of potentially suitable CO2 storage formations across the country, as part of the research by the Regional Partnerships, shows that some areas have ample storage capacity while others appear to have little or none. Thus, implementing CO2 capture at some power plants may require pipeline transportation for several hundred miles to suitable injection locations, possibly in other states. Although this adds cost, it does not represent a technical hurdle because long-distance, interstate CO2 pipelines have been used commercially in oilfield EOR applications. Nonetheless, EPRI expects that early commercial CCS projects will take place at coal-based power plants near sequestration sites or an existing

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CO2 pipeline. As the number of projects increases, regional CO2 pipeline networks connecting multiple industrial sources and storage sites will be needed.

Policy-Related Long-Term CO2 Storage Issues Beyond developing the technological aspects of CCS, public policy need to address issues such as CO2 storage site permitting, long-term monitoring requirements, and liability. CCS represents an emerging industry, and the jurisdiction for regulating it has yet to be determined. Currently, efforts are under way in some states to establish regulatory frameworks for long-term geologic CO2 storage. Additionally, stakeholder organizations such as the Interstate Oil and Gas Compact Commission (IOGCC) are developing their own suggested regulatory recommendations for states drafting legislation and regulatory procedures for CO2 injection and storage operations.5 Other stakeholders, such as environmental groups, are also offering policy recommendations. EPRI expects this field to become very active soon. Because some promising sequestration formations underlie multiple states, a state-bystate approach may not be adequate. At the federal level, the U.S. EPA published a first-ofits-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.

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Long-Term CO2 Storage Liability Issues Long-term liability of storage sites will need to be assigned before CCS can become fully commercial. Because CCS activities will be undertaken to serve the public good, as determined by government policy, and will be implemented in response to anticipated or actual government-imposed limits on CO2 emissions, a number of policy analysts have suggested that the entities performing these activities should be granted a large measure of long-term risk reduction.

RD&D Investment for Advanced Coal and CCS Technologies Developing the suite of technologies needed to achieve competitive advanced coal and CCS technologies will require a sustained major investment in RD&D. As shown in Table 3, EPRI has estimated that an expenditure of approximately $8 billion will be required in the 10year 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

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Clean Coal Technology Hearing

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. 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 criticalpath 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, ultrasupercritical, and advanced ultra-supercritical. We‘re talking about advanced ultrasupercritical 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. Table 3. RD&D Funding Needs for Advanced Coal Power Generation Technologies with CO2 Capture

Total Estimated RD&D Funding Needs (Public + Private Sectors) Advanced Combustion, CO2 Capture Integrated Gasification Combined Cycle (IGCC), CO2 Capture CO2 Storage

2008–12

2013–17

2018–22

2023–27

2028–32

$830M/yr

$800M/yr

$800M/yr

$620M/yr

$400M/yr

25%

25%

40% 80%

80%

50%

50%

40%

25%

25%

20%

20%

20%

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Mr. Hollinden. That‘s correct. The Chairman. Anywhere in the world? Mr. Hollinden. That‘s correct. The Chairman. Am I right, though, that even for the ultra-supercritical that gets you to 42 percent, we have not implemented or used that technology to the extent it‘s been used elsewhere in the world? Mr. Hollinden. Yes, sir. That‘s correct. The Chairman. Why is that? Why are we so behind some of these other industrial countries in doing that? Mr. Hollinden. You know, as representative of the National Coal Council, you know, our study here was related to CO2 control. So, I feel like that, you know, I could answer that as, from my, according to me—— The Chairman. Yes, go right ahead. Mr. Hollinden [continuing]. Not, for the Council— The Chairman. Don‘t, just give us your own perspective on it. Mr. Hollinden. You know, I came out of the coal industry, I mean, I worked for Tennessee Valley Authority for a number of years, I‘ve been involved in coal. In the early days, these technologies were not very reliable. So, you know, in the United States we put plants on, coal was cheap and we wanted the plants to run. So we put on technologies that ran very effectively, very reliably without much interest, I shouldn‘t say interest, but much need for efficiency because coal was so cheap. So, it didn‘t make a whole lot of difference. The Chairman. So efficiency was much less of a priority than reliability? Mr. Hollinden. Absolutely, absolutely. The Chairman. So, we didn‘t really put much pressure on, or much priority on getting the most efficient possible plant? Mr. Hollinden. That is the way it is today, too. The Chairman. Right. OK. Mr. Phillips, let me ask you—you made reference to the dispatch order and the fact that even if we were to build some of these highly efficient plants, the reductions in emissions would not be that great because they would be very far down in the dispatch order. I thought that‘s what I heard you say. Mr. Phillips. That‘s right, yes. No—one of the reasons why those costs increased so much is that, for instance, in a pulverized coal plant you‘re going to be using almost 30 percent of the plant‘s output to compress the CO2 and put it in the pipeline. So therefore, the overall, the effective efficiency of the plant goes down dramatically and because of that the operating costs of the plant for a given amount of megawatts is higher. So, just to get the lowest cost electricity, the way it‘s run now, you know, the cheapest plant goes on first, the second cheapest second, and so forth. So these plants would be further down the dispatch order, unless there‘s some kind of an incentive for them to capture that CO2 and put it in the ground. So, that‘s what I was talking about. We‘re probably looking at something on the order of $20 a ton or so. The Chairman. The dispatch order is currently and historically determined on the basis on what gets you the cheapest power?

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Mr. Phillips. That‘s correct. Particularly in our deregulated States where there‘s a, you know, competitive generation. It‘s simply a matter of who bids the lowest. They get picked first. The Chairman. What if there were a change in policy that got us to a point where we had a dispatch order that was dictated by how you get the fewest emissions? Mr. Phillips. Well, that would certainly change things. The Chairman. Would that significantly incentivize development of these technologies in a way that they are not currently incentivized, or use of these technologies, I guess? Mr. Phillips. Right. I haven‘t really looked into the details. I‘m more of a technologist than a policy person, so I can‘t say specifically, but obviously right now, the way the situation is, there‘s not an incentive and so any type of mechanism that did make an incentive would obviously be a help. The Chairman. All right. I‘ve used my time. Senator Domenici, go right ahead. All right. Senator Craig, you, would you? I‘ve got a list here. Senator CRAIG. I was going to say, I was not here first, Mr. Chairman. The Chairman. OK. I guess Senator Barrasso was next. Excuse me, I got out of order here. Go ahead.

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STATEMENT OF HON. JOHN BARRASSO, U.S. SENATOR FROM WYOMING Senator Barrasso. Thank you very much, Mr. Chairman. As you know, Wyoming produces more coal than any other State, almost 500 million tons of coal, and people in Wyoming are familiar with the unit trains, the 100 cars carrying coal out of the State. As they talked, for every four cars, three are carrying coal, and one is carrying water, because that‘s how it is until it gets to be used. People, as consumers, want affordable energy, and we‘ve become more dependent on international sources of energy, and the more we can do to become energy independent, I think the better it is for our Nation, and clearly, the better it is for my State. The technology needs to be there, for efficiency, so that we can generate more electricity from the same amount of coal, but the people of Wyoming would agree that we‘re at a unique position now. I‘ve been in the legislature in Wyoming, legislators have been to the mines, have seen the technology, we have an entire Wyoming infrastructure authority, looking at some of the things that are important to us, as a State, because we think we can be very helpful in making the Nation energy independent. In a program called Leadership Wyoming, for 7 years in a row, people travel around the State, bipartisan, looking at what we can do, and we look at coal technology, coal-to-gas, coal-to-liquids— ways to convert coal into electricity and then build the transmission line to move the energy in a more efficient way. When I look at this—and you say you want to try to find the right incentives for the carbon dioxide, one of the thoughts is, carbon dioxide can be used for enhanced oil recovery from oil wells, and you know, if you could get the technology so that, in a place where you have oil wells, like Wyoming, and you have coal, like Wyoming, and the carbon dioxide can

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be used from one to the other, than the carbon dioxide can be pumped into the wells to enhance, and gain more energy. I guess the first question would be—wouldn‘t Wyoming be the best place in the world to do all of these things? Even though you‘re all from the East Coast? The additional question is, how do we get this done? I mean, you‘re looking for incentives, but we need to get this technology advanced, throwing a lot of money at it in 1 year isn‘t going to solve it in a year. There‘s a Wall Street Journal article yesterday, Australia Pushes Clean Coal, there, you know, coal reserves in Australia and in the United States, in China—is America going to have to lead the world in coming up with the technology, and then sharing it internationally with some of these others? What‘s the best way? Mr. Bauer. I appreciate your insights, Senator. The question— obviously EOR is probably one of the early places that we can use CO2. In fact, one of the issues and challenges of EOR, is where do you get the CO2, so most of the EOR, to date, in the country has been using naturally occurring CO2, and most of it has been in the Permian basin. Anthropogenic CO2 is about three to four times as expensive, and that puts a chill on the economics around EOR. So, having an abundant supply of CO2 that was at cost, substantially more competitive than it presently is from man-made, would be very helpful. So, that leads to your question about capturing CO2, and using it effectively. I think the simple answer to that is yes, but right now, the policy and dynamics around capture that don‘t really foster that effort, it‘s purely a marketplace decision, and as you‘re probably aware, the gasification facility in North Dakota sends EOR up to the Weyburn Facility in Canada, to do EOR. That CO2 pipeline was invested in by DOE, the Federal Government, to evaluate how does that work? It‘s been very, very, profitable for the company, and I think the information we‘ve gathered about large- scale injection of CO2 has been very helpful. I don‘t know if that helps you with your answer, but I think that capture technology that will get the economics down to capturing and separating CO2 is an essential part, just as Jeff was talking about, as far as just dealing with electricity costs. Senator Barrasso. It just seems, Mr. Chairman, that so much has to do with BTUs, and how to capture the energy, and how to do it in a clean, efficient way, and I think that we can really go a long way, when you just look at the amount of coal resources that are available in this Nation. I mean, there is this source of energy, and the more that we can do, and the more that we can encourage, you know, as a Government, to put clean coal, and all those technologies, coal liquification into gas, into liquids, the better it‘s going to be for our Nation, and our own energy independence. Thank you, Mr. Chairman. The Chairman. Thank you very much. Senator Salazar.

STATEMENT OF HON. KEN SALAZAR, U.S. SENATOR FROM COLORADO Senator Salazar. Thank you. Thank you very much, Chairman Bingaman, and Senator Domenici for holding this hearing. I remember our committee hearings on the Energy Policy Act of 2007, whatever the name is, that we just passed. The dialog that we had in this

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committee with Senator Thomas, Senator Barrasso, and Senator Tester who, and others who were very interested in the coal issue, and how we can deal with the most abundant resource that we have here in America today, and try to use it as one of those items on the menu that gets us to address the very critical energy issues that our country faces. Today, as I understand, we‘re looking at—based on the latest oil prices, $72 per barrel, and I think we‘re going to continue to see a robust agenda on the part of the United States Congress, to try to figure out ways of moving forward toward energy independence. I‘ve always said those drivers are not only National security and economic, but they also now have to do with our environmental security here as a country, and that seems to be the challenge with respect to how we move forward with coal resources. So, my question to you has to do with respect to how we might be able to reconcile the use of coal with the challenge that we face, regarding global warming, and how, specifically we might be able to use coal-powered energy for hybrid plug-in vehicles. I think two- thirds of our oil today is currently used for transportation. Plug-in hybrids, I think, have a tremendous opportunity in terms of dealing with the transportation issue, and it also seems to me to provide a great opportunity for our coal resources and our coal industry to be able to produce electricity and to sequester the carbon from those plants. So, I‘d just like, starting with you, Carl, going through and commenting how the hybrid plug-in technology is also related to what we do with coal development and carbon sequestration. Mr. Bauer. I think it‘s an astute observation, Senator, we did a study at NETL just recently in looking at the alternatives to liquid transportation fuels, and plug-in hybrids was one of the areas that we thought was a way to reduce the dependency on the imports, or the demand on fuel liquids. So, obviously that increases the demand for electricity, and 50 percent of electricity comes from coal. I would suggest that the large base load plants—nuclear and coal—as well as renewable portfolios, would have an opportunity to contribute more to transportation fuel offset. So, back to your question—how does coal deal with that? Or even natural gas combined cycles, when you have a CO2 issue? Again, we go back to having good, solid technology for capture at a lower economic cost, and the ability and the regulatory framework for decisions to be made in the marketplace to take that CO2 captured and put it someplace for storage, long-term, or we‘re looking at trying to find ways to use CO2 as a product, not just as a waste problem. So, for example, we‘re stimulating algae growth to see what we can do to get more efficiency out of the carbon by creating biodiesel from the algae. That adds to the offset of the carbon, and provides electricity for plug-ins, and you have two ways of addressing liquid fuels that way. Senator Salazar. Mr. Hollinden. Mr. Hollinden. The National Coal Council did not look at hybrid coal technologies, so I would be speaking for myself, as opposed to the Council. If that‘s OK? Senator Salazar. Go ahead, give me a quick remark and then we‘ll go with someone else. Mr. Hollinden. I think one of the overriding issue that I have with all of these technologies, is a continued negative press we get with ―dirty coal.‖ You know, and it doesn‘t help our communities, when they hear this, that coal continues to be dirty. Every time we pick up a paper, we hear of ―dirty coal‖ and ―clean gas.‖

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In fact, when these clean coal technologies, advanced coal combustion technologies, gasification technologies are implemented in 15, 10 or 15 years with CO2 control, they‘re going to be cleaner than gas. It‘s never put in the paper like that. Senator Salazar. Well, let me—— Mr. Hollinden. I think our folks need to understand, our people need to understand—— Senator Salazar. [continuing]. Let me just say this, Jerry, from my point of view, we have struggled in this committee, many of us come from coal-rich States, and I do, and I support the coal industry in my State. How we reconcile the development and use of our coal with the environmental realities of the consequence of coal, is something that we all struggle with. It seems to me that so long as transportation consumes two- thirds of our energy, it‘s going to continue to be a National security driver that all of us are going to agree, we need to do something with. So, I would encourage you and the National Coal Council and others to look at how we use coal in connection with our transportation needs, and specifically looking at plug-in hybrids. Jeff, can you just make a quick comment on it? Mr. Phillips. Yes, EPRI has been looking at plug-in hybrids for quite awhile, and in fact, we just issued a joint report with NRDC on the impact of plug-in hybrids on overall emissions in the United States economy, and it shows that indeed, this is a favorable pathway. I mean, when you think about it, as costly as it may be to put CO2 capture on the back end of a coal plant, it would be even more costly to put it on the back end of an automobile. If you look at a future electric power sector that is decarbonized with solar/wind, solar and coal plants with carbon capture, we basically will have a carbon-free fuel that you could, then, to run your automobiles. Senator Salazar. OK. Thank you. Mr. Phillips. I think it‘s a very wise policy to pursue. Senator Salazar. My time is up. Thank you. [The prepared statement of Senator Salazar follows:]

Prepared Statement of Hon. Senator Ken Salazar, U.S. Senator from Colorado I want to thank Chairman Bingaman and Ranking Member Domenici for holding today‘s hearing on clean coal technologies, and efforts to capture and store carbon dioxide. I am proud of our achievements on clean coal technologies in the Energy Policy Act of 2005 and on carbon sequestration in the Energy Savings Act of 2007. There is more work to do, however, particularly given the very real near-term as well as longer-term opportunities for carbon capture and storage and the commercial deployment of advanced coal utilization technologies. So I appreciate the efforts of Chairman Bingaman, Ranking Member Domenici, and the committee staff putting this hearing together. My home state of Colorado is endowed with many natural resources, including vast coal resources. In Colorado, 71% of the electricity we produce is generated with coal. Colorado consumed 18.9 million tons of coal in 2004, generating 37.5 million megawatts of electricity. Most of this coal comes from Colorado, but some of it is from Wyoming.

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Coal is our most abundant domestic energy source. It provides more than 50% of our nation‘s electricity needs, and America has enough coal to last more than 200 years. Unfortunately, CO2 pollution from coal combustion is a main cause of global warming, which threatens my state‘s water resources, our economy, and our quality of life. Fortunately, there seems to be more than one way to reconcile coal use with protecting our climate, through new low-carbon technologies such as Integrated Gasification Combined Cycle (IGCC), Oxycoal and ultra-supercritical combustion technologies. In addition, advancements in capturing carbon and safely sequestering it underground will allow our country to use coal, and at the same time reduce CO2 emissions. I am proud of the work this Committee did in the Energy Savings Act of 2007 to promote research, development and deployment of carbon capture and sequestration technologies, and to do an assessment of our nation‘s carbon storage capacity. What we learn from the national assessment may be valuable in determining optimal locations to place coal gasification and other new power plants to put them near areas where the CO2 emissions can be safely sequestered. Advances in technology indicate that a coal plant using combined cycle technology, carbon capture and storage, and biomass as part of the fuel source can result in far lower greenhouse gas emissions. It is my understanding that even some coal-to-liquid processes can use up to 30% biomass in the feedstock, which reduces the CO2 emissions from the process. The use of a renewable fuel like biomass in these plants presents a great opportunity to allow for an expanded use of coal without adding to global warming. I also believe plug-in hybrid electric vehicles present an important opportunity to utilize coal—to make electricity—as a source of transportation fuel, and thus to displace large quantities of petroleum-based transportation fuels. Because two-thirds of our transportation fuels are derived form petroleum products, plug-in hybrid electric vehicles powered by electricity generated from renewable sources and from advanced coal power plants with carbon capture and storage will enable us to achieve greater energy security, economic security and environmental security in this country. Thank you Chairman Bingaman and Ranking Member Domenici for holding today‘s hearing so that we can learn more about how our country‘s greatest fossil fuel resource can be used to power our homes and businesses as well as to fuel our automobiles. The Chairman. Senator Domenici. Senator Craig. Either one, whoever wants to go.

STATEMENT OF HON. PETE V. DOMENICI, U.S. SENATOR FROM NEW MEXICO Senator Domenici. All right, thank you. Thank you very much, Mr. Chairman. Let me say that it‘s very, very important that a hearing like this one occur. We must go before our Congress, and before the people of this country the facts about coal, and coal in our future. Incidentally, if you wonder what deep thoughts I was exchanging views with the man on my left and the man on my right, in case you wonder, the three of you, I was telling him, each of them, that you are dressing much better these days. [Laughter.]

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Senator Domenici. Mr. Salazar, I was talking about the coal industry being dressed up in pretty good attire these days, there must be that there‘s something good on the horizon. In any event, I‘m with you. I wanted to ask some questions, panel one. Carl—the Department of Energy‘s goal is, ―To develop by 2012, fossil fuel systems with 90 percent CO2 recapture, 99 percent storage, at less than a 10 percent increase in the cost of energy.‖ I‘ve noticed that the National Coal Council makes a clear recommendation in their report to the Secretary that technologies should not be abandoned today, just because they can not immediately meet high capture expectations, early in their development cycle. Can you explain this concept in greater detail? It is an important one—to what extent do the existing clean coal programs at the Department account for it? Mr. Bauer. Thank you, Senator. Yes, I will attempt to clarify that. I believe what the National Coal Council is recommending, and what the Department of Energy and National Energy and Technology do in the implementation of fossil program, it‘s R&D, so it wouldn‘t be R&D if we knew the answer, we‘d just go and do it. As we go through R&D, we do systems analysis of the research, as well as the application, to see that if the technology would, in fact, work, would it be economically viable, so that someone would buy it and put it to work? Because they have to go back into the dispatch rate base. However, having said that, it depends on what stage of development the technology is in. Early in the technology, an analysis that suggests it doesn‘t work, may suggest why—from the economic standpoint—it wouldn‘t be acceptable, and that could then be resolved with further technical efforts. So, instead of abandoning that approach, it‘s wise to recognize the issue, and see how that issue can be further dealt with, technologically, so that technology does come forward. It‘s also important for us to have multiple paths forward, because as they go down the line, go to the races, not all of them are going to make it to the other end, but the more opportunities we have to get to the other end within the budget allowance, it makes good decisions to get there. It also, chronologically speaking, gets us to technological solutions, sooner, and I hope that helps, Senator. Senator Domenici. You got it. In terms of our ability to retrofit the existing coal fleet for CO2 capture and storage, we must account, not only for predictable increases in electricity demand, but also the inevitable losses in the output of existing plants that seek to incorporate and capture technologies. What implications do you believe this trend will have for the pace at which carbon dioxide capture, and existing plants, can be achieved? Even once those technologies have reached commercial availability? Carl, you want to do it? Mr. Bauer. OK, I‘ll take that on. I think that, again, as Jeff alluded in his testimony—if we were just to, for example, to quickly provide an insight to this. If we were to take today, and then Congress put into law, and regulations were in effect, they would say that we have to capture half of the CO2 from the existing fleet. Right now, our calculations suggest, on existing technology, that would be about a 15 percent reduction in delivery of electricity, 15 percent reduction in the efficiency at the end point of delivery.

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That translates to the need, if you want to deliver the same amount of electricity that we presently have—when you think about with the plug-ins, you need more—that would mean we need 42 gigawatts of additional power capacity to offset the loss of power required to deal with the CO2 capture and sequestration challenge of taking 50 percent of the CO2 from the existing fleet, and putting it into sequestration. That‘s a huge—42 gigawatts, coupled with all the other growth that we need—is a huge amount of power to generate, or to replace, figuring a plant takes 6 to 8 years to get through permitting and construction, whether it‘s nuclear or coal, those are pretty ideal times. It‘s probably more like 8 to 10 years, natural gas combined cycle, if we‘re lucky, 3 to 4 years, but then for every 25 gigawatts of gas, you need another 1 trillion cubic feet of natural gas supply. So, the challenge is very surmountable, and the economic impacts. By the way, if we did that, our numbers predict about an increase to about $85 a megawatt, compared to existing fleet, presently $25 megawatt as of older plants. So, it‘s a substantial economic, not just technological challenge. Senator Domenici. Thank you very much. Mr. Phillips. Can I also respond to that, Senator? Senator Domenici. Jeffrey, it‘s your question, your answer, too. Mr. Phillips. Yes, well, EPRI recently put out what we call our Prism Analysis, or some people call it our wedge chart, which shows how we could remove CO2 from the emissions of the electric power sector using various projects, and in that analysis we show that you could drop down to 1990 CO2 emission levels by 2030, and in that analysis, we did not assume any retrofitting of CO2 capture. Only CO2 capture on new coal plants. Now, we‘re also doing very aggressive things on the energy use side—better efficiencies in the homes, increases in solar and wind usage, increases in nuclear power, and higher efficiency for existing plants. That was the one retrofit that we said was, you can go back into existing plants and improve their efficiency, and reduce emissions by maybe 5 percent just doing that. The problem with retrofitting is that some plants, it might be cost-effective, other plants, they‘ve already had so many other things retrofitted to them, that you‘d have to put the CO2 capture stuff on the other side of the highway, and it would get very, very costly. Senator Domenici. Thank you very much. Thank you, Mr. Chairman. [The prepared statement of Senator Domenici follows:]

Prepared Statement of Hon. Senator Pete V. Domenici, U.S. Senator from New Mexico Good morning, I want to thank the Chairman for scheduling this important hearing. Coal is our most affordable and abundant fossil fuel. We generate over half of our electricity with coal. But coal is a versatile feed-stock as well, and electricity is not the only product we can make from it. During our recent energy debate, there was a desire to support new alternative uses of coal. However, there was stiff resistance to those efforts, largely based on concerns about the cleanliness of coal.

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

STATEMENT OF HON. BYRON L. DORGAN, U.S. SENATOR FROM NORTH DAKOTA Senator Dorgan. Mr. Chairman, Thank you very much. It‘s interesting that we meet during a week when oil is at $78 a barrel, and are now talking about coal, which of course, is our most abundant resource. It‘s also interesting that all of these hearings have changed, because we‘ve come to an intersection that‘s a new road for us, and a new intersection. We

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are not going to talk about coal development in the future, without talking about climate change and CO2 capture and sequestration. The question on that is not whether, it is how, and when? Because only addressing how and when, only then will we be able to—in my judgment—have full use of the most abundant resource that we have. I wanted to mention a couple of things. Senator Domenici and I chair the Appropriations Committee that funds these projects and accounts, and Senator Domenici has chaired that same Subcommittee on Appropriations, and now, is now the Ranking Member. For example, we have—carbon sequestration in 2007, we had $100 million. The Administration has requested in their 2008 budget, $79 million. We put in $132 million. So, the Administration was proposing 20 percent less than we actually spent in 2007. Advanced research, about the same, almost a third less. You know, a range of these accounts are not being funded the way— one would expect if this is a priority, than you boost funding in research, especially in these areas of carbon capture and sequestration. That has not been the case. We have, however, increased that funding in our subcommittee, believing it‘s a priority. I want to mention one more thing, and then I‘m going to ask you a question. In North Dakota, most of you know we have the nations only coal gasification plant, we make synthetic natural gas from lignite coal. We also have built a pipeline to the oil fields in Alberta to transport CO2. We capture about 50 percent of the CO2, we send it to Alberta, Canada, they invest it in their oil wells, to increase productivity of marginal oil wells. Now, I read recently that there are—and I don‘t know whether this is a good report—but I read that some suggest that there are over 200 billion barrels of oil that remain as residual oil in partially produced wells, or mature oil fields. By contrast, for example, the Saudis, we believe, have reserves of around 270 billion—that‘s the largest reserve in the world. This 200 billion would be about 10 times of what we expect our reserved to be. If that‘s the case, and if we can find beneficial use of carbon sequestration, by investing in these oil fields, and dramatically increasing the supply of domestic oil, we‘ll have done a lot of things that are important: unlocked our ability to use coal, dramatically improved our capability to increase oil supplies, and also protected our air shed. That‘s why this hearing is so unbelievably important. Because, I mean, it will determine what kind of energy future we have, if we get these things right. I‘m not certain, by the way, Future Gen is the right approach, by building one huge plant. I think there are many ways to try to figure out, how you combine various technologies, and evaluate what the combination of various technologies mean, in terms of practical capability for the future? We‘ve sort of loaded this into one big wagon and said, ―All right, we‘re going forward with this big wagon.‖ I‘m not so sure that we shouldn‘t have broken it into a number of different parts. Having said all that, let me ask—are the three of you optimistic, or pessimistic, or have mixed feelings about the proposition of our being able to really find the methods of capture and sequestration which unlocks our ability to use this resource? Do you feel optimistic we can do this in a reasonable timeframe, and do it well, Carl? Mr. Bauer. I‘m very optimistic we can do that. I think we‘ve already had, through the regional partnerships, and the National Laboratories and the universities that have been engaged heavily in this, as well as the oil and gas industry, which has been doing EOR for a long time, a lot of information that indicates carbon capture and storage, the storage part is very doable. We know we can do capture today, the problem with capture today is the

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economics around it, can we afford to do it today at the price that it would drive our electricity price in this country? Electricity and GDP seem to run very parallel to each other, as opposed to energy, which is slightly lower, because we are much more efficient at using our energy. So, I believe the answer is yes, we can do that. Having the regulatory framework for an industry that doesn‘t do that as a normal cause is important for them to make the business decisions and be able to build it into the rate base, or whatever approvals they have to go with the Commissioners. I also believe we have capture and separation technologies that over the next decade will substantially improve the costs, and get toward the DOE goals. I can go over those another time, but I believe so. Just as one sidelight to the EOR—for all of the EOR that‘s been done in this country to date, we have only produced 1 billion barrels of oil from EOR. So, the Senator‘s right—there is a 200 billion barrels, or if you go down below 5,000 feet, there‘s probably 400 billion barrels that are possible, that could be recovered, however, that‘s technologically possible, not economically viable without better technology or cheaper CO2. Senator Dorgan. Are the others optimistic? Mr. Hollinden. Yes, I am, too. From a different perspective, I‘m with an architect engineering company, and you know, over the last 30 years, every challenge that‘s been thrown at the coal and utility industry has been met, whether it‘s been SO2, whether it‘s been NOX, whether it‘s been particulates, now it‘s mercury—— Senator Dorgan. Mercury. Mr. Hollinden [continuing]. Now we‘re looking at CO2, you know? I mean, we can bring the solutions, you know, to the table. I mean, that‘s what we‘re here for, and, as engineering companies, and developers, and as my colleague just said—it‘s a function of cost, and risk today of these technologies. Remember, we can develop CO2 removal, quickly, but that CO2 has to go somewhere. I think we‘ve got to remember that we‘ve got to do this simultaneously. We‘ve got to be developing sequestration technology at the same time we‘re developing CO2 control. Because, we can be removing CO2, and have no place to put it. It‘s a lot different from the SO2 removal, and NOX in there, where you can put sulfur dioxide material, you know, in wall board plants on the ground. You remove CO2, and you haven‘t demonstrated a place to put it, you know, you have to shut that facility down. Senator Dorgan. Jerry, you complained about not getting good press for the coal industry, I‘d remind you that the statement—bad news travels halfway around the world before good news gets its shoes on. It‘s something we understand here, and I understand, I understood your complaint. Mr. Phillips. Mr. Phillips. Yes, Senator, I am also optimistic, but it‘s going to take a sustained effort. I told some engineering students at Virginia Tech, this is your moon shot, this is your generation‘s moon shot, that‘s the level of effort that it will take to make this happen. We did put a man on the moon, and we did it in 10 years. We‘re talking about something that we need to do in 20 years, it can happen, and I think that EOR is going to be a very key bridge to making that happen. Because, as you point out, you can make money from that. I used to work in the oil business, and so I‘ll give you a general rule of thumb—take the price of oil in dollars, per

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barrel, divide that by 2, and that‘s the price in dollars per ton that the oil industry should be willing to pay for CO2 in enhanced oil recovery. So that‘s if it‘s $73 today, then that‘s what— about $36.5 per ton. Now, unfortunately, those numbers right there are based on technology that‘s probably going to cost us $50 a ton. So, it doesn‘t quite cover the cost, but it sure covers a lot. If we could use that, his, Carl Bauer‘s program has done an analysis that shows that if we just captured CO2 from half of the new power plants that are built between now and 2025, use it for enhanced oil recovery, we could double United States domestic oil production. Senator Dorgan. That‘s a very important piece of information. I‘ve gone over my time, but I thank the Chairman. Thank you very much. The Chairman. Thank you very much. Senator Craig.

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STATEMENT OF HON. LARRY E. CRAIG, U.S. SENATOR FROM IDAHO Senator Craig. Well, in that very exciting concept, Jeff, you excited me more when you talked about your desire to have an AMC Pacer. I, too, wanted one. [Laughter.] Mr. Phillips. I had to settle for a Gremlin. Senator Craig. I didn‘t even get that far. Well, we were farming and ranching in those days, and there was no money in cattle, so my dad and I couldn‘t afford even the Gremlin, let alone the Pacer. [Laughter.] Senator Craig. That‘s probably why I drive a Honda Element today. Something in my mental background that would suggest I kind of like big boxes. [Laughter.] Senator Craig. Anyway, having said that, you talk about the legal challenges, the good news, the bad news, and the bad news/ good news—— Mr. Phillips. Yes. Senator Craig. Walk us through the ultimate legal challenges that you see that we can be players in that continue to allow the technology and the industry to move in the directions we want it to move in. Mr. Phillips. All right, well, one of the biggest things is just, just, you know, who owns the CO2 once it goes into the ground, who‘s going to be liable if it starts to leak back out—— Senator Craig. The Big Belch, in other words. Mr. Phillips. Yeah, or it finds a stray oil well that we didn‘t know about, and it starts coming up there, are you liable to pay money? Or are you just liable to fill up the hole? Do you have to capture additional CO2 somewhere else and put that in the ground? You know, and then there‘s, you know, the usual silly things that you‘re going to expect, that somebody‘s, you know, rose bushes die, and they attribute that because of the, you put CO2 in the ground 50 miles away. Those kind of things need to be addressed also.

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Senator Craig. Those are serious things, at the same time, as a percentage of the whole, what percent of the impediment exists in those legal questions today? In your mind? Mr. Phillips. It‘s enormous, it‘s hard to overstate it. Two things that bankers and insurance companies don‘t like is uncertainty. Right now, that‘s all we have when it comes to geologic sequestration of CO2, because we haven‘t done very much of it, nobody really knows what could be the consequences. Nobody knows what the rules are. If I put CO2 underground in the ground that I own, and it goes over to the ground you own, do I have to pay you money for that? Right? I mean, all of these things have to be taken—EOR. We‘ve got the pipeline up in North Dakota, they allow 1 percent of sulfur in that CO2. The pipeline down in Texas, they allow 10 parts per million. What‘s the basis for those two? What am I supposed to design my plant to be able to do? We need some—— Senator Craig. So you need uniformity. Mr. Phillips [continuing]. We need some uniformity. Senator Craig. You need certainty. Mr. Phillips. We just need to know what the rules are going to be. Senator Craig. Legal structure brings that. Mr. Phillips. Right. Senator Craig. OK. Mr. Phillips. I think that the liability question, I think if we‘re going to ask power companies to put CO2 underground for the public good, that we need to provide some kind of a mechanism to say, ―OK, if you follow the rules, and do this the way we want you to, you know, you‘re now exempted from liability after you‘ve met all of those requirements.‖ Senator Craig. I want to thank Senator Dorgan in his new role as chairman of that subcommittee that he spoke of for funding sequestration R&D. I think that‘s extremely valuable as we continue to move this spectrum forward. Having said that, recently the Senate passed an Energy Act of 2007, and in that Act was a section related to carbon capture and sequestration demonstration project at the Capitol Power Plant. I looked at that and thought, ―Gee, that‘s a nice political feel-good.‖ Is it realistic to take one of these old plants in the heart of a capitol city and practice any form of reasonable sequestration? Or carbon capture? Or is that simply a waste of money? Maybe that‘s a question too hard for you to go to. Where should we be doing this kind of R&D, other than in our Nation‘s Capitol. Out in Wyoming? Mr. Phillips. I know two Senators who would—— Senator Craig. Jerry and Carl, I‘m not going to let you off now—— [Laughter.] Senator Craig. We put Jeff on the hook, why don‘t you respond to that? The latter part of the question? Mr. Bauer. I appreciate the latter part, not the first part. Senator Craig. I‘m sure you do. Mr. Bauer. I believe that the plan that we have going forward is a very solid plan. Because, as Jeff was talking about, some of the legal constraints, there‘s also the acceptance constraints. Part of the regional partnership issue is, getting the States—I mean, let‘s face it, this is done locally. We can decide here in Washington what we think is the right thing to do, but the people who have to put it to work and live with it are out there where they live.

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So, part of the regional partnership was both to collect the scientific and technical information required to ensure that this was right and safe in that scale, and to identify the places that it could be done, and it covers 97 percent of the country‘s most probable places, and power and industrial CO2 production, so it‘s covering a broad spectrum of opportunity, and to get the regulators, the State officials, the citizens, the academia of the State and region actively involved so they can understand it, so as this becomes law, and as it becomes regulation, they have already engaged in the process, and so we can continue to move forward, for those of us who got involved in applying CIRCLA and RICLA, we know we went through a decade of legal battles about doing things, because we didn‘t get people comfortable about what was being done, and there were tremendous battles. This is an important issue, to move it forward requires extensive large-scale demonstrations and scientific and technical work around that, but it also requires the work of the people in the area to understand what‘s going on, so that they feel comfortable and acceptable risk around this whole issue. So I think, the question you ask is really, we need to do it out in the States, and the States that have the highest probability of using CO2 capture are the ones that have substantial industrial CO2 generation, or power generation CO2, and do have reservoirs. In fact, that‘s what the regional partnerships represent, and have aggressively got companies to put money up. The regional partnerships don‘t just live off the largesse of the Federal dollars, there is a tremendous amount of investment from the private sector with them. So, I think we‘re getting a tremendous move forward in accelerating the process of acceptance and understanding how to do it legally right there. Senator Craig. Mr. Chairman, and Senator Domenici, the reason that I ask that question—while I understand sometimes we do things that are politically ―feel-goods,‖ the reality is that siting some of these facilities is not unlike how we‘re siting new reactor generator facilities. The easier siting comes where they are, and where there is, in my opinion, a feeling of understanding on the part of the populace, as it relates to the need to site. Case in point, we had a company try to site a major coal—it would have been a merchant generator, a major coal plant in Idaho, 2 years ago. Right by the rail, had its water, could have used Wyoming coal, and the State of Idaho said no. The people said no. Now, I won‘t suggest that it made the siting possibility, opportunity may not have been handled as well as it could have been, but the reality was, and it goes back to what Senator Dorgan is saying, there was a great opportunity here, but it probably occurs where it already is, from a standpoint of acceptance and understanding, and the issue of cleanliness, i.e. non-emitting, is paramount now, in the minds of most Americans. We‘ve got to get this thing done, and the only way we‘re going to do it is in partnerships and investment to get us off from an 80 percent escalated cost. That‘s unacceptable. Thank you. The Chairman. Thank you very much. Senator Sessions has been waiting, why don‘t we go ahead and have you ask your question. Then Senator Tester, and then we have a vote at 10:35, at least that‘s what I‘ve been informed, so maybe we can conclude the questions of these remaining two Senators, and then finish with this panel before we go to vote. Senator Sessions.

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STATEMENT OF HON. JEFF SESSIONS, U.S. SENATOR FROM ALABAMA Senator Sessions. The Economist Report of June 2, reports that coal produces 50 percent of America‘s electricity, 70 percent of India‘s, 80 percent of China‘s, it‘s widely distributed around the globe, noting that China is adding coal-fired, powered plants at a remarkable rate. Two 500–megawatt coal-fired power plants are starting up every week in China, which is each year, they‘re adding more than Britain has, total. So, coal is a real factor in everything that we must think about, as we consider electricity for the future. There was a book by, Mr. Chairman, I believe it‘s Jacquard, a Canadian who analyzed all of this, and global warming, and concluded that fossil fuels capture is the best way, longterm, for America, for the world, to meet our global warming, and energy needs. So, I don‘t know where we are. We certainly have a lot of coal. Let me ask you first, Mr. Bauer, if you have concluded in the next, say 20 years from today, if you produced clean coal with capture, and nuclear-generated electricity, what would be the relative cost of those two, do you have any idea? Mr. Bauer. I would submit that if the research that has been done, and the technologies that are coming forth, implement, in today‘s dollars, let‘s say, we would see, hopefully we‘d be meeting our goals of maybe 10 percent to 15 percent increase in electricity, assuming that the demand for electricity doesn‘t outstrip the supply, and then we get into market dynamics of supply and demand. I think the same thing is true on nuclear power, I happen to come from a nuclear power background earlier in my career, and both opportunities for power generation are substantial base load contributors that, up and running, keep chugging along and generating. So, for coal, CO2 capture at a decent price, and CO2 sequestration being understood and utilized, I think the prices will stay in a very marginal area, and we have plenty of sequestration and storage opportunity, according to the USGS reports, and our analysis of that. Senator Sessions. So, my, my, I guess a consumer goes and pays his bill, he doesn‘t expect a great difference between clean coal cost of electricity and a nuclear base load cost of electricity? Mr. Bauer. I think if you look—one of the problems that I question is a fact of materials availability. If you look at both GE‘s comments on the meeting with Hitachi, and merging to make power plants, they raise their price from the merger a year ago to now by 50 percent, all based on concrete and steel availability. That‘s an issue we‘re not talking about, but that is a big issue of building power plants, capturing CO2, and building nuclear power plants that is really going to drive that price up. Now, if we can get that back under control and balanced by rebuilding our capability to produce—a different issue, I know, Senators—then I think the prices can come back into operation and construction that are reasonable to what we experienced today, a little higher because of having to do additional things. The fact that we‘re down to about 20 percent of what original scrubber technology cost today, at this, the inflated dollars, should suggest we have the same opportunity to go forward with improved technology, and it becoming ever less expensive. Senator Sessions. One of the things I think we would need to ask, and maybe, Mr. Phillips would have an idea or any of the others, it seems to me that there are certain areas of

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the country more capable of storing CO2 than others. A Federal mandate that requires that, do you have any idea—is that true? Should there be any compensations for areas not able to do so? Mr. Phillips. It‘s certainly true that there is some areas that don‘t have good areas underground for storing CO2, unfortunately, my State of North Carolina is one of them, we‘ll have to send a pipeline over the Appalachian Mountains to find a good location, maybe we can send it all the way down to Alabama if you‘ll let us. Whether there should be compensation for that, I don‘t know, but I think it speaks to your first question, which is, we can‘t do it all with carbon capture from coal power plants, we can‘t do it all from nuclear, we can‘t do it all with renewables, there is no silver bullet, what we need is silver buck shot— we‘ve got to try it all. [Laughter.] Senator Sessions. Mr. Chairman, I know your time, I‘ll yield back, thank you, sir. The Chairman. I think the vote is about half over, so let me move, go to Senator Tester.

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STATEMENT OF HON. JON TESTER, U.S. SENATOR FROM MONTANA Senator Tester. Thank you, Mr. Chairman. So that means your answer is going to have to be very concise. I think this is for Carl— the Future Gen project is a—appears to be a pretty decent project, public/private partnership for zero emissions. It appears to be going slower than what I thought. Give me your perspective, tell me what you think on where it‘s at as far as moving along, and tell us what we can do to help push it along. Mr. Bauer. It was an easy question, at least. Senator Tester. See if you can do that in 15 seconds or less. Mr. Bauer. The Future Gen Project, actually, is moving along for a general coal-type utility project, pretty much as they normally do. So, it seems slow, but that is a real sense of what it takes to build these large plants. It has some conditional issues about finding the State and location to put the CO2 in, which has added to the time-frame. 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

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decide they want to put their shoulder to it and keep pushing, rather than kind of going along wondering if they should make the investment. I know that‘s a big challenge for the country. Senator Tester. Thank you, Mr. Chairman. We‘ve got to go. The Chairman. All right. Let me thank all three of you, this has been very useful. We have one other panel that we will return to in about 10, 15 minutes, and resume the hearing. Thank you, we‘re on recess for that period. [Recess.] The Chairman. Why don‘t we go ahead with the second panel. I apologize to everybody for the long delay. They had various problems on the Senate floor getting a second vote accomplished. This second panel, let me just introduce the people here. Mr. Don Langley, who is the Vice President and Chief Technology Officer with Babcock & Wilcox Companies in Barberton, Ohio. Mr. Andrew Perlman, who‘s Chief Executive Officer with Great Point Energy in Cambridge, Massachusetts. Frank Alix, who is Chief Executive Officer with Powerspan in Portsmouth, New Hampshire. Jim Rosborough, who‘s Commercial Director for Alternative Feedstocks with Dow Chemical Company. Bill Fehrman, who‘s the President of PacifiCorp Energy in Salt Lake. Thank you all for being here and why don‘t you each take about 5 minutes and summarize your main points. We will put your full statements in the record. Mr. Langley, go right ahead.

STATEMENT OF DONALD C. LANGLEY, VICE PRESIDENT AND CHIEF TECHNOLOGY OFFICER, THE BABCOCK AND WILCOX COMPANY, BARBERTON, OH Mr. Langley. Chairman Bingaman, distinguished members, thank you for the honor to testify before you today. My name is Don Langley and I‘m the Vice President and Chief Technology Officer for the Babcock and Wilcox Company, a provider of advanced pulverized coal boiler technology and all types of environmental control equipment for the electric power industry. I‘m here today to talk about carbon capture and storage technology or CCS technology for use in the electric power industry. We and other technology providers are actively developing a variety of CCS solutions for coal power plants. While these multiple tracks require different development lead times, commercialization is not too far in the future. With appropriate policy, that is policy that does not pre-select winners, I believe our industry will deliver a variety of technologies for carbon management. Among other options, there are two in particular that I‘d like to discuss. B&W is leading the effort toward commercializing oxy-fuel or what we call oxy-coal combustion technology for carbon dioxide capture. Starting this month we are running privately funded, large-scale oxy-coal tests at our 30 megawatt thermal test facility in Ohio. We‘re also conducting a

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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 NOR, mercury, and SOx. Another area where we are actively working, is improving the efficiency of plants by raising steam temperatures. As with the rest of the industry, and really all across the economy, efficiency improvement pays dividends. B&W‘s goal is to increase efficiency such that CO2 emission levels for a new plant would be 30 percent below today‘s fleet, the average of today‘s fleet. This can help our cause in two ways. First, replacing older, least efficient plants in the existing fleet would allow us to continue to meet energy demands with less CO2 output. But I think even more interesting, this advanced process applied in conjunction with CCS technology will reduce the amount of CO2 needing to be captured, thereby lowering costs for carbon capture and improving total plant economics. Oxy-coal and efficiency gains are two examples of our technology initiatives and now I want to make a few points about deployment. MIT‘s future of coal report recommends building field demonstration projects that capture and store about one million tons of CO2 per year, with a projected cost share of $2 to $3 billion. This multiple project approach is then the first key enabling step leading to commercial-scale early deployment projects with roll-out of commercial projects with CCS then to follow. We agree with MIT‘s recommendations and this is what I would say is putting first things first. Why this is important can be seen in an example roll-out scenario. One deployment scheme, one that the NRDC is advocating consideration of, is a performance standard, whereby over a 10- year period, 10 to 15 percent of the power generation from coal is required to be from low emitting sources. The result would be avoidance of about 400 million tons per year of CO2, while still meeting rising energy demands. I calculate that if this deployment occurred as a new capacity, up to 100 new 660megawatt plants would be required. The investment then would be about $300 billion. My point is, that to enable this type of investment, a solid technology platform must be in place. To do that, we must do first things first. Finally, the timing of this technology roll-out and managing expectations is crucial to ensuring long-term success. B&W believes large at-scale CCS-based demonstration projects can be on the ground and operating in the 2012 to 2014 timeframe. We think this is consistent DOE–EPA efforts to enable geologic storage around 2012. We then project that we could be ready for a large-scale roll- out with commercial performance guarantees around 2018 to 2019 and offer serious carbon storage from coal plants beginning in, perhaps, 2020. I understand that this timeline will be disappointing to some, but the risk associated with an illconceived 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:]

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Prepared Statement of Donald C. Langley, Vice President and Chief Technology Officer, the Babcock & Wilcox Company, Barberton, OH Chairman Bingaman, Mr. Domenici, and Members of the Committee: My name is Don Langley and I am the Vice President and Chief Technology Officer of The Babcock & Wilcox Company. The Babcock and Wilcox Company, headquartered in Barberton, Ohio is a provider of supercritical pulverized coal boiler technology and a leading provider of all types of environmental control equipment for the electric utility industry, as well as for the renewable biomass natural resource sector. I am pleased to testify before you today on critical aspects of delivering carbon capture and storage, or CCS technology for the coal-based electric utility industry. It is well recognized that the utilization of coal is an important element of a national strategy to ensure energy independence. It is also well recognized that to achieve meaningful greenhouse gas emission reductions, a portfolio of technologies will be required, including clean coal, solar, nuclear, wind, and biomass to name a few. The power providers also need options within each of these technologies to suit their specific needs, such as fuel. We would advocate then that it is necessary to avoid legislative provisions that would explicitly or implicitly pick winners in this important competition. Given certainty on performance requirements for clean coal and a clear need for CCS, a free and open market with healthy competition stands the best chance to deliver technology in a cost effective manner. I would start with some overview points. B&W recognizes the value of striving for carbon neutral energy sources, understands the tasks before us to mitigate carbon emissions, and willingly accepts the challenge. We have invested over $100 million over the last five years to develop innovative technology paths forward. We, and other technology providers, are actively developing a variety of climate-friendly solutions for coal power plants. While the multiple tracks require different development lead times, the commercialization trajectories are not too far out into the future. Substantial R&D support and incentives will be needed to attain the interim goal of getting at scale, first-of-a-kind plants on the ground. By ―at scale‖, I mean plants capturing and storing something like one-million tons per year. It is our opinion that the pathway forward consists of establishing these at-scale field demonstration projects, followed by early deployment, commercial scale units with special considerations, such as incentives, all leading to a large scale rollout of clean coal with CCS. Whether this pathway is structured by policy or allowed to occur naturally, these important steps must by completed to enable the investment required to support a large scale rollout of new technology. We must do first things first, the large scale R&D, and not attempt to do second things first by moving directly to large project incentives for projects with high deployment risk. It is important that policy recognize these important steps, and with appropriate policy, our industry will deliver a variety of technologies for carbon management. That is, policy that does not pick winners and addresses first things first is crucial. B&W is pursuing a variety of carbon-friendly technologies. I would like to discuss two of them. B&W is leading the effort toward commercializing oxy-coal combustion technology for carbon dioxide capture. Oxy-coal technology utilizes nearly pure oxygen instead of air in the combustion process which then produces concentrated stream of CO2 that can be stored geologically or used for enhanced oil recovery (EOR). Starting this month, we are running

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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 road- map for driving combustion plant efficiency even higher, to 45 percent, using very high temperature designs which would reduce the CO2 produced per unit of energy by perhaps 30%. This can help our cause in two ways. First, replacing the older, least efficient plants in the existing fleet would allow us to continue to meet energy needs with less CO2 output. Additionally, this very high temperature process in conjunction with CCS will reduce the amount of CO2 needing to be captured, lower the capital investment and the operating costs for carbon capture, benefit the overall plant economics, and justify accelerated implementation. We have been receiving some support from the DOE for this activity as the alloy materials required must be certified for public use and will be used by all the technology providers. To continue to develop this technology, we will need as an industry, to construct a materials test center that will conduct advanced, component based research for the shared benefit of all technology providers. This important R&D function is worthy of funding considerations and we will be soliciting for this support in R&D funding plans. These are two examples of the investment B&W is making to redefine Clean Coal Technology. We believe that MIT, as articulated in the Future of Coal report, has it mostly right with recommendations for extensive, at-scale field demonstration projects, each of which would capture and sequester about one million tons of CO2 per year. The at-scale project approach is the key enabling step that would lead to accelerated commercial scale early deployment projects, followed by a large scale rollout of plants with CCS. We need to do first things first. For example, NRDC is advocating consideration of a proposed performance standard approach whereby, over a ten year period, 10 to 15% of the generation from coal is required to be low emitting power. I calculate that, if this goal were to be attained by building new capacity, up to 100 new, 660MW plants would need to be built, representing an investment approaching $300 billion in today‘s dollars. This is a worthy goal

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as this approach would remove upwards of 400 million tons per year of CO2 from the sector emissions while still meeting rising energy demands. My point is that to enable this type of investment, a solid technology platform must be in place and we must do the first things first. We agree with MIT that only $2 to $3 billion would be required to fund this large scale R&D and one million tons of CO2 per year at-scale field demonstrations. The sooner we start, the sooner we can get to the point where we are storing carbon dioxide in earnest. Finally, the timing of this technology rollout and managing expectations is crucial, particularly if we are to ensure long term success. B&W believes large at-scale CCS based demonstration projects can be on the ground and operating in the 2012 to 2014 time frame. Note that this is consistent with the DOE/EPA efforts to establish geologic storage regulations in the 2012 timeframe. We then project that we could be ready for a large scale rollout with commercial performance guarantees around the 2018 to 2019 timeframe and offer serious carbon storage beginning in perhaps in 2020. I understand that this timeline will be disappointing to some. But, the risk associated with an ill-conceived or rushed initial deployment of CCS technology could result in time lost for serious storage efforts in the future and in lower storage levels in the aggregate. We have to get the long term program right and not rush the short term learning. We believe if we proceed in a thoughtful and deliberate way, we as an industry can and will deliver the results that move our Nation towards meaningful energy security, work towards a worldwide reduction in carbon emissions, and minimizes the impact on our Nation‘s economy while contributing to international competitiveness. Thank you for this opportunity to testify. The Chairman. Thank you very much. Mr. Perlman, go right ahead.

STATEMENT OF ANDREW PERLMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER, GREAT POINT ENERGY, CAMBRIDGE, MA Mr. Perlman. My name is Andrew Perlman and I am Chief Executive Officer of Great Point Energy and one of its co-founders. Thank you for the invitation to testify here today regarding recent advances in clean coal technology and its prospect for deployment at commercial-scale in the near future. As my testimony will explain, I believe Great Point represents a significant breakthrough in clean coal technology and we are on track to deploy our plans at commercial-scale in the next few years. So I‘m here to talk about Great Point Energy and the technology that we have developed, the catalytic gasification technology that we have developed, to convert low cost coal and also petroleum coke and even biomass into pipeline quality natural gas. We‘ve got two major reasons for doing this. One is environmental and the other is economic. From and environmental standpoint, we can take the dirtiest of all commercial fuels and convert it to the cleanest of all commercial fuels. From an economic standpoint, we believe that we can manufacture natural gas for much less than it sells for in the industry. In fact, we were going through our economics and we actually hired Nexent, which is a division of Bectal to do a full economic and engineering analysis of our technology. All the numbers I‘m going to present today come from Bectal. I was going over them with Secretary Bodman

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a couple months ago. One of the things that he pointed was that given the increase recently in, or over the last few years, in the cost of both L&G imports and also new natural gas exploration and production, we can actually be the lowest incremental cost of new natural gas in North America. It is also, the other benefit, that there‘s virtually unlimited resources and reserves available. We can build gasification plants in places like Wyoming and Montana today, and still be building plants 100 years from now without running out of reserves and not have any of the exploration or depletion risk that‘s inherent with natural gas exploration today. Unlike many of our competitors, which have focused on licensing strategies, at Great Point our strategy is to build, own, and operate gas-production facilities ourselves, in close proximity to both coal mines and oil refineries. We think this is important because, while there‘s been a lot of discussion about natural gas over the last few years, there haven‘t been a lot of shovels in the ground. So we think that it‘s very important, that if we want to be able to meet the aggressive timeframes that we‘ve set out, that we make sure that we‘re leading the charge. But we‘re not doing it alone, we are working together with some significant energy companies and over the next few months we‘ll be making announcements of developments that we plan with some of the largest energy companies in this country. Well, we‘re a new a company, we think that we‘re also extremely well positioned to be able to develop the technology. We‘re backed by some of the leading venture capital, in fact, we think the leading venture capital firms in the country, groups like Kleiner Perkins, Draper Fisher Jurvetson, Advanced Technology Ventures, and Vinod Khosla, who you might have seen testify here in the past. I also think we‘ve attracted an extremely experienced management team, people like the former VP of Technology for Bectal, who built two of the four largest coal gasification plants in the United States, as well as, recently, the Chief Process Engineer for Sasol, which operates the largest coal gasification plant in the world, just joined to run our engineering group. We have operating, successfully operating pilot plant facility in Des Plaines, Illinois and we‘ve actually been running extremely successfully on Powder River Basin coal all summer. As I mentioned, we have economics, economic, complete economic and engineering analysis done by Nexant, a division of Bectal, and the economics are extremely compelling. We also, we haven‘t announced it publicly yet, but we also have a technology collaboration with one of the largest chemical companies in the world for technology development and scale-up. Just briefly talking about the technology and how it differs from what conventional gasification is and what you might think of it today in technologies from groups like Siemens and GE and Shell and Conoco. All of these traditional gasification technologies operate at extremely high temperatures, about 1,400 degrees Celsius. At these temperatures, it‘s so hot that the ash in the coal actually melts and forms something called slag and the slag is constantly eating away at the reactor walls. In fact, in order to have significant up-time and reliability, most of these manufacturers recommend that you have a second gasifier on standby so you can always be fixing one while you are running the other. They also require extremely costly equipment. In order to get to those temperatures, you need to inject pure oxygen, which means you have to freeze air down to near absolute zero to separate the oxygen from the nitrogen. Not only is that about 25 percent of the capital costs, but it‘s about 15 to 20 percent efficiency hit on these plants. Also,

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because they‘re at such high temperatures, you need to build them out of, a high temperature cooling equipment out of exotic materials, which raises the cost. But most importantly, all these technologies produce, do not produce pipeline-grade natural gas. They only produce syngas, which is a low-grade, a low-BTU fuel, which is not compatible to pipeline systems and particularly economic to move over long distances. You can upgrade syngas to natural gas, but in order to do that you have to have four chemical plants, all operating at very different temperatures, from near absolute zero all the way up to 1,400 and then back down again to convert the syngas into natural gas. So, you end up with very high complexity, a very low efficiency, high capital costs, low reliability, and high price for a million BTUs of the natural gas. So basically, the way that Great Point Energy solves this problem, is by introducing catalysts into the gasification system. So basically, coal or petroleum coke combines with steam in the presence of heat pressure and the catalyst to produce 99 percent methane or, basically, pure natural gas instead of low-quality syngas. All of the carbon dioxide, the ash, the sulfur, the trace metals, and the mercury are all safely removed as part of the gas clean-up process. The beauty of the situation is that all of the chemical reactions perfectly heat balance. So, actually the heat of, that‘s produced in methanation, which is an exothermic reaction, perfectly offsets the heat required for gasification, which is an endothermic reaction, meaning that we don‘t need to inject any oxygen into the system and we can operate at about half the temperature of normal gasification. So, we don‘t have any of the maintenance or liability issues. We don‘t have to have high temperature cooling equipment because we‘re not at high temperature. But most importantly, at the end of the day, we‘ve produced pipeline-grade natural gas. The Chairman. Maybe you could sum up your testimony here, we‘re running over time. Mr. Perlman. Sure, sure. The importance of that, which was discussed earlier today, is that the places where you can sequester carbon dioxide are not usually, or easily sequester carbon dioxide, are not usually the places where you want to produce electricity, which is in the population centers. So, if you can generate a pipelineable fuel, you can do that mine mouth in places like Wyoming and Montana and Texas, where you actually, where you can easily sequester the carbon dioxide or, in those places, you can actually sell the carbon dioxide today economically for enhanced oil recovery. So, without any involvement from the Government whatsoever, you can actually, economically today, using the only proven carbon dioxide sequestration technology do that and then you can move the natural gas anywhere in the country where it needs to go. [The prepared statement of Mr. Perlman follows:]

Prepared Statement of Andrew Perlman, President & Chief Executive Officer, Great Point Energy, Cambridge, MA Mr. Chairman and members of the committee, my name is Andrew Perlman. I am the Chief Executive Officer of Great Point Energy, and one of its co-founders. Thank you for your invitation to testify today regarding recent advances in clean coal technology, including prospects for deploying this technology at commercial scale in the near future. Great Point is

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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.

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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 precommercial 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 20 11/2012.

Our Technology & Its Benefits Most coal gasification efforts in North America have in common certain things: the recognition that our continent‘s coal reserves are vast; that coal is a key to our energy security and independence; that coal represents a relatively inexpensive source of energy; but that the traditional method of using coal—burning it—is inherently limited, dirty, and makes controlling carbon dioxide emissions extremely difficult and expensive, if not altogether impossible.

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Until now, the best-known coal gasification technologies have been pursued primarily for one particular application, namely direct production of electric power in what‘s called ―integrated gasification combined cycle‖ or IGCC power plants. These technologies almost all operate at extremely high temperature; about 1400 degrees Celcius. At this temperature, the ash in the coal actually melts and forms something called slag. The slag constantly eats away at the reactor walls of the gasifier and leads to high maintenance costs and low reliability. In fact, a spare gasifier is typically required in order to achieve over 90% online availability of the plant so that one gasifier can be fixed while the other one is operating. In order to generate the heat in the system, conventional gasifiers require pure oxygen. This oxygen is generated in a plant which freezes air down to near absolute zero in order to separate the nitrogen from the oxygen. These air separation plants are extremely expensive— 20% to 25% of the capital cost and result in a huge efficency hit because they utilize so much energy and operate at vastly different temperatures from the high temperature gassifier. Finally conventional gasification processes yield synthesis gas, or ―syngas,‖ which consists primarily of carbon monoxide and hydrogen gas instead of natural gas which consists entirely of methane. Chemically as well as commercially, the syngas from conventional gassifier is very different from natural gas. For one thing, few if any pipelines exist to transport syngas, whereas a highly integrated nationwide network exists to transport natural gas. This means that conventional gasification plants must be located next to power production facilities and near major population centers. As a result solid coal must continue to be transported across the country to these facilities at high cost. The combination of conventional gasification technology with power plants designed to burn the hydrogen and carbon monoxide they produce is called IGCC or Integrated Gasification Combined Cycle. The plants are highly complex and very expensive. The syngas from conventional gasification cannot be converted to pipeline quality natural gas without the addition of multiple complex chemical plants and processes. Further, with conventional gasification technologies, unless additional steps are taken essentially all of the carbon that started out in the coal will end up in the atmosphere as CO2. In order to remove CO2 for capture and eventual storage or sequestration, conventional gasification technologies require—in addition to the capital and operating expense of the oxygen plant—the further capital and operating expense of a so-called ―shift reactor.‖ The shift reactor is a separate facility in which the proportion of carbon to hydrogen in the syngas mixture is ―shifted‖ to a hydrogen-rich blend by injecting steam which converts some of the carbon monoxide in the syngas to carbon dioxide. The carbon dioxide is then available as a separate stream for potential capture and storage or sequestration. Many, if not most population centers in the U.S. are located in areas where carbon dioxide cannot easily be sequestered, but these are the locations that IGCC plants need to be built to provide electricity. Therefore it is going to be very difficult to actually sequester carbon dioxide from these plants, even if they are built with technology to capture a portion of the CO2. Great Point‘s technology is different—much simpler, more efficient, lower temperature, and less costly. With the help of a catalyst, we use a single reactor vessel to carry out three different chemical reactions, as a result of which we are able to convert coal directly into pipeline quality natural gas in our gassifier instead of syngas. Roughly 50% of the carbon in the coal is removed and captured as a pure pressurized stream of CO2. In addition to our

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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 nonrecoverable energy in the form of heat (in addition to fouling equipment and adding to maintenance expense). Our potential for cost-effective and sensible CO2 management is much greater than for conventional gasification technologies as well. In Great Point‘s process, CO2 in a separate and pure stream is simply a by-product of our producing pipeline quality SNG. Of course, the CO2 still needs to be compressed for shipment via pipeline to locations where it can be used for enhanced oil recovery (―EOR‖) or otherwise stored or sequestered. That is true of any gasification technology—or, for that matter, any other technology that may allow CO2 to be captured, including proposed oxy-combustion and other post-combustion capture technologies, if they can be made to work. The difference is that Great Point‘s process does not require the capital investment or operating expense of any extra facilities or equipment to produce CO2 as a separate, capture-ready stream. That makes it different from conventional gasification technologies and hoped-for post-combustion CO2 capture technologies alike. Finally, of course, like other gasification technologies, Great Point‘s technology offers the prospect of truly clean coal in a traditional sense. We will produce almost none of the sulfur, oxides of nitrogen, or mercury emissions of power plants that burn coal. Our emissions profile for these and similar pollutants should be as good as, if not better than, the emissions of a natural gas-fired power plant in almost all respects. Clean coal really is possible. Moreover, as I will discuss next, it is also imminent.

Commercial Deployment I recognize that what I‘ve said here about Great Point‘s technology would be of purely academic interest to the Committee if our technology could not soon be deployed at full

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commercial scale. Timing, not just technology, is among your key concerns. I‘m happy to be able to offer good news and encouragement on that front, too. As I mentioned at the outset, Great Point‘s technology has already been demonstrated successfully both at bench scale and at the much larger scale of our test facility which we operated over the past year at the Gas Technology Institute‘s test facility outside Chicago. We will next build a permanent demonstration facility which will be our final step before full commercialization. Our first commercial project operating on pet coke will be constructed in cooperation with a major Fortune 50 chemical company at a site we have already identified and which we are already designing and engineering. We have done a great deal of work for these commercial projects already, in addition to inventing, patenting, testing, and proving the gasification technology that they will rely on. For example, we have screened literally scores of potential sites for the location of our initial commercial projects, and have narrowed down our finalists for the first such project to about six sites. In addition to a siting strategy, we have developed and are now in the process of implementing both a partnering strategy and a project design and execution strategy, so that we may rely on investment-grade industrial partners and largely standardized project designs to help us achieve and sustain an early, efficient, and rapidly expanding commercial ―launch.‖ Our business model is focused on building, owning, and operating these commercial projects ourselves, in conjunction paid construction contractors and in partnership with our strategic industrial allies. As I mentioned at the outset, we expect our first project to begin producing revenue in the 2011/2012 time frame. By 2017—ten years from now—we plan to have at least ten revenue-producing projects in operation and sales revenues of over $3 billion as a company. Almost all will be at full commercial scale. Within a decade our goal as a company is to a material contribution of the North American natural gas requirements from coal and petroleum coke, and from biomass feedstocks as well.

Great Point in Perspective I hope my testimony, the information available on our website (www.greatpointenergy.com), and whatever answers or additional information that I can provide in response to questions or further inquiries from Committee will reassure you that (1) our company, for one, does have a clean coal technology that represents a significant advance, and (2) commercial deployment of this technology is relatively imminent, not some far-fetched dream for the distant future. At the same time, I want to acknowledge three points. First, our company could not be where it is without the great technological innovations and inventions of the scientists and engineers who came before us. Those far-sighted predecessors of ours were encouraged and largely funded by far-sighted predecessors of yours, the men and women who served here in Congress and elsewhere in the U.S. government during the Energy Crisis of the 1970s. This goes to show that government can help. I know that the Chairman has drafted legislation under which the government would again contribute in a substantial way to basic research and development for climate-friendly new energy technologies that may help the global environment while also helping North America become more secure and energy independent. From what I understand of your effort, Mr. Chairman, I applaud it, and hope our company

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may serve as a useful example of the long-term public benefits and private sector ―leverage‖ that government-sponsored energy sector basic research may one day yield. Second, the advanced coal gasification sector is large, and the potential market, both domestically and globally, is huge. There is ample room for several useful and successful technologies in this field, and for many companies developing them. At GreatPoint, we simply intend to do an excellent job, and to do it as rapidly and on as large a commercial scale as may be reasonably possible. Finally, in this spirit, there are additional things that I believe Congress and the Administration could do that would be useful to us and other companies focused on clean uses of coal that would speed the development of clean coal technologies. These include a $0.50/Gasoline Gallon Equivalent production tax credit for the generation of natural gas from North American coal, petcoke, and biomass much along the lines of the credits available for ethanol production; as well as loan guarantees and grants for coal conversion to clean natural gas. In short, we believe the conversion of coal to natural gas is at least as compelling, if not significantly more compelling, than traditional coal gasification and also as important to the nations energy independence as ethanol. We simply ask that it be treated equally with these other technologies when government support is available. In addition, we believe that setting a price floor for natural gas produced from highly efficient gasification of domestic feedstocks below which government guarantees would kick-in, would provide the assurances to enable large-scale, multi-billion dollar facilities to be rapidly deployed in the market without any substantial direct government incentives, unlike many other areas of the clean energy industry. My associates and I at Great Point would welcome the opportunity to discuss our technology and recommendations further with you and your staff. Thank you again for this opportunity to appear before you. The Chairman. Thank you very much. Mr. Alix, go, is it Alix, is that the right pronunciation? Mr. Alix. Thank you. Yes. The Chairman. Thank you.

STATEMENT OF FRANK ALIX, CHIEF EXECUTIVE OFFICER, POWERSPAN, PORTSMOUTH, NH Mr. Alix. Good morning Mr. Chairman and members of the committee. Thank you, for being invited here to speak. My name is Frank Alix and I‘m CEO of Powerspan Corp. Powerspan is a clean energy technology company headquartered in New Hampshire. I‘m cofounder of the company and a co-inventor on several of Powerspan‘s patents. We‘ve been in the business of developing and commercializing clean coal technology since 1994. In order to fund technology development, we‘ve raised over $70 million from private institutional corporate investors. Our most significant clean coal technology success to date has been the development and commercialization of our ECO technology, which is an advanced multi-pollutant control technology to reduce emissions of sulfur dioxide, nitrogen oxides, mercury, and fine particles, in a single system. First Energy Corporation of Akron, Ohio, has been a major supporter, providing the host site for ECO commercialization activities as well as substantial financial contributions. Over

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the past 3 years, we‘ve successfully operated a 50-megawatt-scale, commercial ECO unit at First Energy‘s Burger plant in Shadyside, Ohio. This unit has demonstrated ECO has the capability of achieving emissions below best available control technology for coal plants and comparable to outlet emissions from natural gas combined cycle power plants. ECO also produces a valuable fertilizer product, avoiding the landfill disposal of flue gas desulphurization waste. Furthermore, the ECO system minimizes water use because it requires no waste water treatment or disposal. Commercial ECO cost estimates prepared by perspective customers and their engineers indicate that ECO capital and operating costs would normally be about 20 percent less than the combined cost of separate control systems required to achieve the comparable reductions. For a 600-megawatt plant, this equates to an annual cost savings of about $5 to $10 million. Although the utility industry has a conservative approach to new technology adoption, the environmental and economic advantages of our ECO technology has resulted in some significant commercial progress. Within the past year, First Energy announced the commitment to install an ECO system on its Burger plant, units four and five, an installation valued at approximately $168 million. Additionally, AMP-Ohio recently announced a commitment for ECO for its proposed 1,000 megawatt plant in Meigs County, Ohio. This commitment was driven in part by the promise of a new technology Powerspan is developing for CO2 capture, which we call ECO2. The ECO2 process is a post-combustion CO2 capture process for conventional power plants. The ECO2 technology is readily integrated with our ECO process and is suitable for retrofit to the existing coal-fire generating fleet as well as new coal-fired plants. Since 2004, Powerspan and the Department of Energy‘s NETL have worked together to develop the ECO2 process. The regenerative process uses ammonia to capture CO2 in the flue gas. The CO2 capture takes place after other pollutants are captured. Once the CO2 is captured, the ammonia-base solution is regenerated to release CO2 in a form that‘s ready for geological storage. Pilot scale testing of our ECO2 technology is scheduled to begin in early 2008 at First Energy‘s Burger plant. The pilot unit will process a one-megawatt flue gas stream and produce about 20 tons per day of CO2, achieving a 90 percent capture rate. We plan to provide the captured CO2 for onsite sequestration in an 8,000 foot well. First Energy is collaborating with the Midwest Regional Carbon Sequestration Partnership on the sequestration test project. This pilot program could be the first such project to demonstrate both CO2 capture and sequestration at a coal-fired power plant. The ECO2 pilot program provides the opportunity to confirm process design and cost estimates and prepare for large-scale capture and sequestration projects. Initial estimates developed by DOE, indicate that our ammonia-based capture process could provide significant savings compared to commercially available amnion-based CO2 capture technologies. Our own estimates, based on extensive lab testing, indicate commercially CO2 systems should be capable to capture and compress 90 percent of CO2 from conventional power plants at a cost of about $20 per ton. Regarding prospects for deploying ECO2 at commercial scale, Powerspan and its commercial partners, Siemens and Fluor, are currently evaluating opportunities to deploy commercial-scale demonstration units to process 100 megawatts of flue gas and produce approximately one million tons of CO2 per year for use in enhanced oil recovery or geological sequestration. A project of this size would be among the largest CO2 capture operations in the

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world and would serve to demonstrate the commercial readiness of ECO2 for full-scale power plant applications. With the anticipated success of the pilot unit, we would expect our first commercial demonstration project to begin operating in 2011 and full-scale commercial units to be operating by 2015, with commercial guarantees. Although large-scale projects, such as taking ECO2 from a one megawatt pilot to a 100 megawatt commercial demonstration contains some risks, we believe the risk is manageable because equipment use in our process, absorbers, pumps, exchangers, and compressors, have all been used in other commercial applications. The technology in ECO2 is innovative process chemistry. Commercial application of this unique technology holds no special challenges that we can foresee, and therefore has a high probability of commercial success. We agree with the recent MIT study on coal that places a high priority on the commercial demonstration of CO2 capture from several alternative coal combustion and conversion technologies, as well as CO2 sequestration at the scale of one million tons per year. However, such an undertaking will require substantial resources. The recently proposed 30 percent investment tax credit and $10 to $20 per ton CO2 sequestration credit is exactly the type of incentive needed and shows the Senate is prepared to provide the required leadership. It is important that such incentives apply to both pre- and post-combustion technologies and require that CO2 capture and sequestration be accomplished at a reasonably large scale. Additionally, in order to move large-scale CCS projects ahead as rapidly as possible, the incentives should to apply to retrofits at existing coal-fired plants, otherwise we‘d need to wait for new plants to be built, which could unnecessarily delay the demonstration. I‘ll wrap up now because I‘m a bit over. Thank you for the opportunity and I‘d be happy to answer questions later. [The prepared statement of Mr. Alix follows:]

Prepared Statement of Frank Alix, Chief Executive Officer, Powerspan, Portsmouth, NH Good morning Mr. Chairman and Members of the Committee. Thank you for the opportunity to share Powerspan‘s perspective on advances in clean coal technology. It is an honor to be invited here to speak. My name is Frank Alix and I am CEO of Powerspan Corp. Powerspan is a clean energy technology company headquartered in New Hampshire. I am a co-founder of the Company and a co-inventor on several of Powerspan‘s patents. Powerspan has been in the business of developing and commercializing clean coal technology since its inception in 1994. In order to fund technology development, the company has raised over $70 million from private, institutional, and corporate investors. Our most significant clean coal technology success to date has been the development and commercialization of our ECO® technology, which is an advanced multi-pollutant control technology to reduce emissions of sulfur dioxide (SO2), nitrogen oxides (NOX), mercury (Hg), and fine particles (PM2.5) in a single system. FirstEnergy Corp. of Akron, Ohio has been a major supporter, providing the host site for ECO commercialization activities, as well as substantial financial contributions.

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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 coalfired plants. Since 2004, Powerspan and the U.S. Department of Energy‘s (DOE) National Energy Technology Laboratory (NETL) have worked together to develop the ECO2 process. The regenerative process uses an ammonia-based solution to capture CO2 in flue gas. The CO2 capture takes place after the NOX, SO2, mercury, and fine particulate matter are captured. Once the CO2 is captured, the ammonia-based solution is regenerated to release CO2 in a form that is ready for geological storage. Pilot scale testing of our ECO2 technology is scheduled to begin in early 2008 at FirstEnergy‘s Burger Plant. The ECO2 pilot unit will process a 1–MW flue gas stream and produce 20 tons of CO2 per day, achieving a 90% CO2 capture rate. We plan to provide the captured CO2 for on-site sequestration in an 8,000-foot well. FirstEnergy is collaborating with the Midwest Regional Carbon Sequestration Partnership on the sequestration test project. This pilot program could be the first such project to demonstrate both CO2 capture and sequestration (―CCS‖) at a coal-fired power plant. The ECO2 pilot program provides the opportunity to confirm process design and cost estimates, and prepare for large scale capture and sequestration projects. Initial estimates developed by the U.S. Department of Energy indicate that our ammonia- based CO2 capture process could provide significant savings compared to commercially available amine-based CO2 capture technologies. Our own estimates, based on extensive lab testing, indicate that commercial ECO2 systems should be able to capture and compress 90% of CO2 from conventional coal-fired power plants at a cost of about $20 per ton. Regarding prospects for deploying ECO2 at commercial scale, Powerspan and its commercial partners—Siemens, and Fluor—are currently evaluating opportunities to deploy commercial scale demonstration units that would process a 100–MW flue gas stream and produce approximately 1,000,000 tons of CO2 per year for use in enhanced oil recovery or

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geological sequestration. A project of this size would be among the largest CO2 capture operations in the world and would serve to demonstrate the commercial readiness of ECO2 for full-scale power plant applications. With anticipated success of the ECO2 pilot unit, we would expect our first commercial demonstration project to begin operating in 2011, and full-scale commercial units to be operating by 2015. Although large scale-up projects, such as taking ECO2 from a 1–MW pilot to a 100–MW commercial demonstration, contain some risk, we believe the risk is manageable because the equipment used in the ECO2 process—large absorbers, pumps, heat exchangers, and compressors—have all been used in other commercial applications. The ―technology‖ in ECO2 is innovative process chemistry. Commercial application of this unique technology holds no special challenges that we can foresee, and therefore has a high probability of commercial success. We agree with the recent MIT study on coal that places a high priority on the commercial demonstration of CO2 capture from several alternative coal combustion and conversion technologies, as well as CO2 sequestration at a scale of 1 million tons per year. However, such an undertaking will require substantial resources. The recently proposed 30% investment tax credit and $ 10–20 per ton CO2 sequestration credit is exactly the type of incentive needed and shows the Senate is prepared to provide the required leadership. It is important that such incentives apply to both pre-and post-combustion technologies, like ECO2, and require that CO2 capture and sequestration be accomplished at a reasonably large scale. Additionally, in order to move large-scale CCS projects ahead as rapidly as possible, the incentives should apply to retrofits at existing coal-fired plants. Otherwise, we would need to wait for new plants to be built with CCS, which could unnecessarily delay such demonstrations for several years. There is growing concern that the need to address climate change combined with the expanding use of coal presents an intractable problem, one where the tradeoff is between severe environmental or economic consequences. At Powerspan, we believe the necessary clean coal technology is near at hand, and the tradeoff need not be severe. Our ECO technology, which has the capability to produce a near zero- emission coal-fired power plant, is commercially available, is being commercially deployed, and will set a new emission standard for coal-fired plants. Our ECO2 technology, which is being developed for 90% capture of CO2 from conventional coal-fired plants, is on a well-defined path toward commercialization using currently available commercial equipment. The cost of wide spread deployment of CO2 capture technologies such as ECO2 appear manageable, particularly when one considers that post-combustion approaches such as ECO2 preserve the huge investment in existing coal-fired power plants, and avoid the need to replace a major portion of the power generating fleet. Thank you Mr. Chairman. I would be pleased to answer any questions that you or other Committee members may have. The Chairman. Thank you very much. Mr. Rosborough, go right ahead.

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STATEMENT OF JIM ROSBOROUGH, COMMERCIAL DIRECTOR, ALTERNATIVE FEEDSTOCKS, THE DOW CHEMICAL COMPANY, MIDLAND, MI Mr. Rosborough. Thank you chairman, Senator Domenici, and members of the committee. My name is Jim Rosborough from the Dow Chemical Company. Thanks for the opportunity to provide our views today on clean coal technologies and the practicality of their deployment. We appreciate your efforts in the search for environmentally friendly and economically sustainable energy. Today, I‘d like to emphasize a few points on the subject. First, Dow is one of the world‘s largest chemical companies and is also one of the world‘s largest energy consumers. We convert the equivalent of one million barrels of oil every day in the chemicals, plastics, and electricity. The availability of low cost, price stable feedstocks is critical to our business and to our global competitiveness. Mr. Chairman, I can‘t emphasize this point enough. This is a strategic issue for the Dow Chemical Company. Second, we are confident that coal gasification is a viable way to enhance our nation‘s energy security and industrial competitiveness. It can also be an important part of the solution for climate change. Finally, to successfully implement industrial gasification at the right scale, we need a strong public-private partnership that will reduce the risk of investment and ensure the development of cost-effective carbon management techniques. The program we envision is doable now. Multiple commercial-scale industrial gasification plants that generate—sorry— that integrate the production of chemicals, plastics, fuels, and electricity can be a reality on the ground in this Nation within 10 years and they can greatly improve our energy security without breaking the carbon bank. Senator Domenici. Why 10 years? Mr. Rosborough. It takes a while to build a major-scale industrial complex, Senator. That‘s what we‘re talking about is, rather than a small demonstration facility. We‘re talking about major integrated sites. Thanks for the question, and we can talk more about it in a little bit. In 2005, our Chief Executive Officer, Andrew Liveress, appeared before this committee and said that we really want to invest in the United States, but that Dow has been discouraged from doing so recently because the United States has some of the highest and most volatile natural gas prices in the world. Since his testimony, natural gas and oil prices have remained high. In spite of Dow‘s improvements in energy efficiency, our feedstock costs jumped to $22 billion last year, up from $8 billion only a few years prior. Clearly, we need a real solution to reverse this trend in the United States. Gasification can be a big part of the answer. It is versatile technology that can convert coal, biomass, wastes, or just about anything that contains carbon into virtually any product that society needs. A consortium of industrial companies, in partnership with the Government, is the best way to implement industrial gasification technology at the right scale and integrate all of the sectors that I just mentioned previously. There are two principle barriers that stand in the way of deployment. First, is the high capital costs of initial construction. Gasification plants are more than capital intensity of their conventional alternatives. A direct loan program or something to the equivalent nature is

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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:]

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

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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 sustain- ability commitments. In addition, we:

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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 byproduct of biodiesel processing. Other sustainable energy inventions are on the horizon. For example, we are developing new roofing materials that convert solar energy to electricity, a project the Department of Energy has chosen to jointly fund because of its promise. In addition to our technology advancements, we are calling for strong government action on climate change, energy efficiency, conservation and security of supply. As a member of the U.S. Climate Action Partnership (USCAP), we are encouraging Congress to promptly enact mandatory, market-based climate legislation. We have been recognized as leaders in energy efficiency and are believers that improved conservation offers the greatest prospect to reduce carbon dioxide (CO2) and other greenhouse gas emissions. We have also made real progress in this area. In 1994, Dow made a public commitment to sustainability. We pledged then to improve our energy efficiency 20% by 2005. It was an ambitious goal—far greater than other heavy industries—and the fact that we achieved a 22% improvement is a great source of pride to our company and our employees, not only because of the reduction in our energy use, but because we did it profitably. We invested roughly $1 billion dollars and saved nearly $5 billion, which we believe is a very good return on our investment. During this period we saved 900 trillion Btu, enough energy to power all the homes in California for a year. Since 1990, we have improved our energy intensity by 38% and reduced our absolute greenhouse gas emissions by more than 20%, a level that exceeds Kyoto Protocol targets. We believe there is more to do, and have set a further goal to reduce our energy intensity by another 25% by 2015. This relentless dedication to energy efficiency and our achievements is evidence that we know how to optimize the footprint of our existing assets and improve the efficiency of succeeding generations of technology.

Why Gasification? Industrial gasification provides technologically prudent yet flexible paths to a lower carbon future and greater U.S. energy security, as it would help the country diversity with abundant, domestic energy resources while helping address the high cost we and other manufacturers pay for raw materials.

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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***). Gasification technology can also be utilized to convert a wide range of biomass— plant matter, wood waste and crops—to energy and chemicals, replacing hydrocarbon fuels and feedstocks and reducing overall emissions of CO2. Additionally, it can turn high-volume waste streams (e.g. plastics, municipal solid waste) into strategic fuel and feedstock sources. By innovatively combining bio-based materials with high-energy materials such as coal, wastes streams that are otherwise ―non-recyclable‖ (or only mechanically recyclable) can be converted into useful virgin materials, achieving a closed-loop, ―cradle-to-cradle‖ life cycle for virtually any chemical or plastic. Challenges Capital Costs.—Even a ―small‖ gasifier is a complex piece of equipment. Multiple gasifiers and related unit operations (i.e. an oxygen plant) are typically required, resulting in high capital costs relative to other technologies. A coal to liquids (CTL) gasification plant requires some three to four times the capital of a comparable oil refinery. Lack of Experience.—While gasification technologies have been around since the early 20th century, relatively few in the chemical or fuel industries have hands-on experience, contributing to the perception that gasification carries a greater-thanaverage 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 longterm investment climate for gasification projects. Carbon capture and sequestration is arguably the most needed and widely acceptable technology solution for CO2 emissions control. Financing the development of the sequestration technology and infrastructure should be a priority for government investment. Gasification plants using hydrocarbon feedstocks, with their concentrated CO2 exhaust streams, are well suited to a national sequestration program as it develops. Economically attractive uses of CO2, such as enhanced oil recovery, should be encouraged. Co-gasification of biomass and wastes can help to reduce consumption of hydrocarbon feedstocks and overall CO2 emissions. Some studies have shown that biomass can be cogasified with coal at a rate up to 30% of total input. With industrial gasification, a significant portion of the carbon will find its way back into the supply chain as useful product. Carbon-based products such as carpeting, water and sewer pipes, building insulation, packaging and automotive components can all be derived from either the naphtha co-product of a CTL plant, or directly from the syngas.

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Dow’s Plan We congratulate the committee and the Senate for its recent passage of an energy bill to improve U.S. energy security. But we respectfully submit that more needs to be done, particularly on the supply side. Our search for alternatives to the feedstocks we use currently have led us to believe that industrial gasification technology is mature and scaleable, could greatly improve America‘s energy security, and that building a full-scale plant of this kind in the United States can best be accomplished through a public/private partnership. We have expressed an interest in leading a consortium in the U.S. to demonstrate the technology on a commercial scale (approx. 80,000–100,000 barrels/day). Raw material feedstocks to produce syngas are abundant, present throughout the United States, and available at low costs. However, the major hurdle for any such plant in the U.S. is the high capital cost and obtaining financing. The promise of syngas plants will matter little without the right policy and incentives. Financiers are hesitant to provide the capital needed for a facility of the size needed to prove its worth. That is why we believe the federal government must dramatically increase its commitment to the development of a syngas infrastructure. Even with oil prices where they are today, the payback period deters private entities from building these plants (Chart 1****). The government needs to jump start a public-private partnership to develop a syngas industry by providing a focused capital investment, enacting stable policies and permitting the military to enter into long-term off-take agreements. Loan guarantees and tax credits alone won‘t make this happen. Based on our analysis, direct government loans covering up to 50% of the cost of a few early-mover projects seems to be what is needed to demonstrate viability (Chart 2****). We remain open to comparable alternatives. Our view is that absent a scaleable solution like industrial gasification, which brings a range of benefits, the U.S. over time will become a bit player in the petrochemical industry. Without significant U.S. action to reduce demand, increase supply and provide alternatives, the center of gravity of the petrochemical industry, and its downstream production, will shift to the Middle East, Africa and Asia. This movement has already begun. In the last two months alone, Dow alone has announced joint ventures totaling around $30 billion in these areas. More than 10,000 direct and 60,000 indirect jobs will be created—many of which could have been created in the United States, but for the high cost of energy, particularly natural gas, a commodity that, unlike oil, is regionally, rather than globally priced. Global competitors, integrated to low cost, often stranded feedstocks will be able to land competing products in the U.S. at a natural gas-equivalent cost of roughly half the U.S. gas price. The U.S. must continue to drive demand reduction through energy efficiency, increase domestic oil and natural gas production, and promote alternative and renewable forms of energy and feedstock. Syngas from coal, biomass or a combination of the two is a potential low-cost alternative to the high and volatile cost of natural gas, gas liquids and petroleum byproducts that are the basic building blocks of the modern chemical industry. We expect that with the government‘s assistance, we—in partnership with others—would prove the worth of a U.S. syngas industry. Syngas can be converted to chemicals and plastics as well as electricity and transportation fuels. With it, Dow can make virtually all of the products we currently manufacture.

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Coal is important because its abundance and established supply chain make it most capable of meeting syngas needs on a scale that will be economically meaningful.

Carbon Benefits Dow fully understands that we must live in a carbon-constrained world. And we support Congress‘ desire to improve the carbon efficiency of coal technologies. The CO2 must be managed. We agree with many members of this committee that in the near term, carbon capture and storage (CCS) should be developed to ease the U.S. transition from a fossil fuelbased energy economy to a low-carbon paradigm and eventually a zero-emissions future. Industrial gasification plants will help demonstrate options for CCS. Gasification of hydrocarbon feedstocks produces relatively pure CO2 streams, which can be used for economic purposes—enhanced oil recovery or CCS. But these are not the only ways to limit atmospheric CO2 emissions. Our involvement in the gasification process (a chemical process) offers another way to maximize the use of CO2. The chemicals we make bind the carbon into useful products like plastic (Figures 2–4*****). Our initial analysis suggests that were a syngas plant to run on 30% biomass, as experts tells us is possible, and were we to make products from the plant‘s feedstocks, we could bring the CO2 footprint of a CTL plant down by about half (Figure 4). Further, we expect that through this consortium with other stakeholders, relying on experts such as those here today and our history of optimizing the chemical process will assure carbon efficiency improvements.

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Coal-to-Liquids We‘ve heard on both sides of the Capitol from members of both parties that coal must remain a key part of the U.S. energy mix and that any ultimate climate change policy must require a ―Manhattan Project‖ for coal. The question is how to use coal in a carbon constrained world. In other words, how do you grow coal without breaking the carbon ―bank‖? We submit that one of the best ways is through coal gasification. Dow believes we can participate in a coal-to-liquids plant and that doing so will improve its carbon footprint, as stated above. Initially, these plants are likely to run mostly on coal (Figure 3). Over time, their operators will gain experience and the facilities will become more efficient, reducing their greenhouse gas emissions. Biomass will be increasingly used, further reducing greenhouse gases. And by utilizing sequestration in such a setup, there can be a net reduction in greenhouse gases compared to an oil refinery of comparable size (Figure 4). Dow has announced its intent to form a joint venture in China to build coal-tochemical 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.

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STATEMENT OF BILL FEHRMAN, PRESIDENT, PACIFICORP ENERGY, SALT LAKE CITY, UT Mr. Fehrman. Thank you, Mr. Chairman. My name is Bill Fehrman and I am President of PacifiCorp Energy, which provides power to PacifiCorp‘s customers in Utah, Oregon, Wyoming, Idaho, California, and Washington. We are responsible for implementing the policies that will ultimately be decided through the discussions that we‘re having today and beyond. It‘s also important to note that we do not develop the technology, but we do have the requirement to justify the technology to our regulators, so that we can be seen as making prudent decisions on behalf of our customers. We are constantly examining different ways to provide generating resources to serve our customer‘s fast-growing demands, while at the same time, trying to meet the strict new environmental requirements that we have today and that we expect to have in the future. Supercritical pulverized coal technology is available today and emits, basically, the same amount of CO2 as IGCC technology. We‘ve used supercritical coal technology as a consideration or a bridge, if you will, while new approaches are developed to burning coal, such as IGCC with carbon sequestration and capture capabilities. It‘s critical to understand that IGCC‘s technology and carbon capture are two completely different things and can be applied to different sorts of opportunities. For instance, as you know, IGCC gasifies the coal and then it runs through a standard combustion turbine, whereas carbon capture and sequestration essentially takes the CO2, separates it, compresses it, and injects it deep into the earth. Both IGCC and pulverized coal technologies can be compatible with carbon capture and sequestration, they are not one against each other. In our case, no outside body, for instance, tells Starbucks what it can charge for products or what costs it can include in its prices. That‘s not the case for a public utility such as PacifiCorp. Our regulators determine the rates that we can charge and most States only allow recovery on those costs that can be demonstrated to be prudent and undertaken at a very costeffective manner. This structure, just by itself, does not encourage utilities to become technology developers. Instead, we purchase those technologies from vendors and it‘s their shareholders, not our customers or our rate payers who earn the rewards of the success of bear the cost of the failure. In evaluating any of these technologies, we ask ourselves three key questions. Is it commercially proven and reliable? Are the risks and costs comparable to other available technologies that we have in front of us? Will our State regulators allow recovery of reasonable and prudent development costs in our rates? With respect to the IGCC technology today, our answer to each of these questions is no. The four IGCC plants operating today are not large-scale, they have not consistently achieved capacity factors comparable to supercritical plants and they do not capture and sequester CO2. Much of the technology remains unproven and we have not received cost or performance guarantees from vendors that can give us reasonable assurance that we can meet the prudent cost recovery requirements that our regulators will demand. However, it‘s these unknowns that demonstrate why more research in this area is so critical and why this debate has to continue.

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Most of the information on IGCC is based on the use of higher heat content bituminous coal. We believe that one of DOE‘s highest priorities should be IGCC R&D with sub bituminous coals and pre- and post-combustion technologies for capturing carbon from both IGCC and pulverized coal-fired plants. Government support can clearly help direct the industry toward this higher risk investment and away from the default choice of natural gas. Support should include such things as accelerated depreciation, investment and production tax credits, R&D funding, public and private partnerships to develop and construct commercial-scale plants. In fact, in this regard, PacifiCorp was recently chosen as the Wyoming Infrastructure‘s partner to pursue a high altitude IGCC plant using Powder River Basin coal. I would also add that our existing Jim Bridger sits atop some of the most promising CO2 storage locations in the United States. Carbon capture and sequestration currently utilized it enhanced oil recovery must also fit into this picture, but it faces major challenges, as you‘ve heard before from others. So, we‘re sure our Federal research, development policy dollars go. From our view, support the development of IGC plants with a focus on the most abundant coal types, i.e., there is a significant amount of coal that is available, particularly in the State of Wyoming that has a potential to solve many of our issues in the long-term, provide R&D funding for low-cost, pre- and post-combustion CO2 capture process for both pulverized coal and IGCC, and provide funding for the advancement of technologies that result in higher availability, increased performance and cost, and eliminate the liability for sequestering CO2, that many of us view is one of the most significant risks of this, going forward. In order to move us toward a low-carbon future, IGC technology must be economically competitive, reliable and more broadly applicable to the lower-ranked coals and higher altitude conditions that exist in many of our locations across the United States, but particularly in the West. Remember that a combined IGCC-carbon capture and sequestration power plant does not exist anywhere in the world today, yet many talk like it‘s readily available. As we debate our future energy policy, we must not lose track of these facts, and the economic impact of developing this technology. Our customers will pay for our decisions, and when they turn on the switch, they expect the lights to come on at a reasonable price. Thank you for the opportunity to be here, and I‘d be happy to answer any of your questions. [The prepared statement of Mr. Fehrman follows:]

Prepared Statement of Bill Fehrman, President, Pacificorp Energy, Salt Lake City, UT Thank you, Mr. Chairman for the opportunity to testify today regarding the electric utility industry perspective on the potential of integrated gasification combined cycle (IGCC) technology. My name is Bill Fehrman, and I am the president of PacifiCorp Energy, the power generation and supply division of PacifiCorp. PacifiCorp provides electric utility service in six states across the West—Utah, Oregon, Wyoming, Idaho, California and Washington. My comments today reflect my views and experiences in this industry and are

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not meant to represent the industry as a whole, although I believe our experiences are largely consistent with those of other companies considering investments in clean coal technologies.

Background on Pacificorp PacifiCorp‘s generation mix includes nearly every major resource available to our industry: coal, natural gas, hydroelectric, wind and geothermal power. Along with our sister company, Iowa-based MidAmerican Energy Company, we are the largest on-system utility owner of renewable electricity in the country through our corporate parent, MidAmerican Energy Holdings Company, and we are also looking to expand our nuclear capability.

Key Considerations With Regard to Generation Resources

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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 Utahbased Rocky Mountain Power system. At the same time, we must meet strict new environmental requirements, particularly in the Pacific Northwest. It is critical that we move forward in a way that does not expose our customers to undue risk. In determining our energy supply and resource acquisition strategies for next-generation technologies, we ask three key questions: (1) Is the technology commercially proven and capable of providing reliable power for our customers? (2) Is the cost and risk of the technology comparable to other available technologies? (3) Will our state regulators support these projects and allow recovery of reasonable and prudent costs of development to be included in rates?

Utilities Are Not Encouraged to Be Technology Developers The answers to each of these questions must be in the affirmative in order for public utilities to invest billions of dollars in new technologies. However, at the present time with respect to IGCC technology, the answer to each of these questions is no. Utilities are largely agents of the customers we serve. We assemble and integrate the various elements of electric service—power generation or acquisition, transmission, delivery, and customer service—to provide our customers with the most reliable system possible at a reasonable price, while complying with all federal and state environmental policies that may exist. For the most part, utilities do not individually develop technologies; we purchase technologies and operate them. The reason this is true might not be immediately obvious, but it is important to understand. No outside body tells Starbucks what it can charge for its products or what costs it can include in its prices. That is not the case for public utilities. State and federal regulators determine the rates that utilities can charge, and state statutes limit the costs that can be considered for inclusion in rates. Most state statutes only allow costs to be

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included in rates if the utility can demonstrate that the actions that gave rise to the costs were undertaken in a cost-effective manner, which is typically defined in terms of risk-adjusted least cost.

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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:

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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 nondispatchable. In spite of rapid growth in recent years, thanks to Congress‘ extension of the Section 45 production tax credit, non-hydro renewables still only provide less than two percent of the country‘s generation mix. We are proud to be an industry leader in integrating renewables into our fuel mix. However, many of the most suitable locations are already under development, and transmission costs are likely to increase substantially. Furthermore, as renewable portfolio standards mandate ever larger percentages of energy, additional sources of backup generation will need to be installed to provide the reliability necessary due to the intermittency of wind. Hydroelectricity is also an emissions-free renewable generation source, but we are unlikely to see new large-scale hydro facilities built in the United States due to concerns about impacts on fish, river systems, and some endangered species. Indeed, the West is experiencing significant pressure to remove existing hydroelectric dams. Nonetheless, we should explore ways to maintain the hydro resources we have in an environmentally responsible way, explore cutting-edge, low impact hydro technologies, and work to gain greater efficiency from existing facilities. Some refer to energy efficiency as a ―fifth fuel,‖ and we agree that energy efficiency represents one of the best opportunities to both meet resource needs and near-term emissions reductions. We commend the Senate, and this Committee specifically, for passing a bipartisan package of energy efficiency requirements in this year‘s energy bill. However, efficiency improvements only help flatten the growth of the demand curve; they do not eliminate the need for new generation resources. Energy efficiency and renewables alone will not meet the electric energy needs of this country.

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What is IGCC? As others have testified before this Committee, IGCC technology is designed to combine a chemical gasification process with traditional combustion turbine based processes to generate electricity at comparatively high rates of efficiency and low emissions levels. While I know that members of this Committee understand the difference, I want to emphasize for the record that IGCC technology and carbon capture and sequestration are not the same thing. IGCC describes a highly integrated two-step process: (1) coal gasification to produce a gas-based fuel that can be burned in a combustion turbine; and (2) power generation. Carbon capture and sequestration is a potential complementary add-on to this technology that would convert the carbon in the synthetic gas to carbon dioxide, separate and compress it, and ultimately inject it deep beneath the Earth‘s surface, resulting in permanent sequestration.

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Is IGCC a Proven Technology? Worldwide, there are four operational IGCC electricity generating plants with generation capacity of roughly 250 megawatts each. None of these plants captures or sequesters carbon dioxide. The two plants operating in the United States (in Florida and Indiana) were built with federal funding assistance as part of the Department of Energy‘s Clean Coal Power Initiative demonstration projects. IGCC is not a commercially viable technology at this time. No large scale, utility-size plant has been built, and much of the technology is unproven, which is why we have not been able to obtain price and performance guarantees from any vendors. With the technology unproven, with unclear costs, and with no guarantees from vendors, we are unwilling at this time to expose our customers to these risks. Furthermore, these plants have not consistently achieved capacity factors comparable to readily available supercritical pulverized coal plants. Moreover, most of the information on the operation of IGCC technology is based on the use of higher ranked, higher heat content bituminous coal or pet-coke. Lower ranked subbituminous and lignite coals with lower heat content and greater moisture content can be gasified, but at lower efficiency. The industry needs significantly more experience working with these coals, especially given the quantity of these types of coals in the Western United States. The application of IGCC at higher altitudes presents unique issues that must be addressed given that a large quantity of low rank coals are found in elevations that exceed 4,000 feet. At high elevation, the air pressure—and hence the density of air—is lower. The output of all combustion turbine-based resources, not just IGCC plants, is thus reduced at higher elevations. The output of a combustion turbine is reduced approximately 3 percent with every 1,000 feet increase in altitude. For a project operating at 5,000 feet (which would apply to much of PacifiCorp‘s generating fleet in the Rocky Mountain region), output losses would be 15 percent. In simple terms, this increase in elevation results in a reduction in output, although the capital cost is essentially unchanged. Relocating the facility to a lower altitude and moving the electrons by wire may seem a reasonable option, but this would move the generation away from many of the most potentially suitable carbon sequestration sites in the

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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.

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Comparing IGCC and Supercritical Pulverized Coal Based on our studies, vendor and engineering-constructor information, and recent bids, as well as information we have seen from other utilities at this time, a supercritical pulverized coal plant costs roughly 25–30 percent less than an IGCC plant. Moreover, supercritical pulverized coal technology is mature and reliable, whereas IGCC is still far from having acceptable performance parameters, particularly with regard to lower ranked coals and high altitude applications. It is also important to note that today IGCC and supercritical pulverized coal emit basically the same amount of carbon dioxide. Using traditional measures of prudence and cost-effectiveness, and given our current estimates of the ―cost‖ of carbon dioxide emissions, supercritical coal technology is the clear risk-adjusted, least-cost choice at this time. Unfortunately, in our view, a number of states have imposed emissions reductions requirements that effectively prohibit the inclusion of electricity produced by supercritical technology. Furthermore, some states are requiring that IGCC have a carbon footprint equivalent to natural gas-fired generation. This course of action essentially would require implementation of carbon capture and sequestration. Though wellintentioned, 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

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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 costeffective clean generation technologies as soon as they are available commercially.

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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.7 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. 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.‖8 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.

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Research and Development Efforts

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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/ postcombustion carbon dioxide capture processes. 3. Provide specific development goals for the advancement of IGCC technologies that focus on major components that will result in higher availability, increased performance and lower cost. 4. Provide a regulatory framework in which captured carbon dioxide is considered a commodity and not a waste/pollutant. 5. Provide financial incentives for permanent geologic carbon dioxide sequestration. 6. Develop a regulatory framework for injection wells and carbon dioxide pipelines. 7. Develop regulatory and policy certainty to eliminate all liability for sequestering carbon under scientifically-based federal standards. 8. Develop a regulatory and policy position that supports the use of supercritical pulverized coal as a bridge until new technologies are proven and can be commercially deployed.

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Summary Before IGCC technology can provide a critical path toward a low-carbon future, it must be made more economically competitive, reliable, and more broadly applicable to lower rank coals and higher altitude conditions. Policy makers must understand, however, that combining a chemical process (gasification) with a mechanical process (coal-based power generation), and then capturing and sequestering the gasified carbon, is not simple and does not exist today anywhere in the world. Policy makers must also appreciate that our first obligation as public utilities is to provide reliable electricity supplies for all our customers and that deploying new technologies to reduce carbon emissions will not come without significant increases in cost for these customers. We share the desire of Congress and the American people to proactively take actions to reduce and avoid carbon dioxide emissions as much as possible and as quickly as possible. However, technical challenges remain and emission reduction programs must be designed with these realities in mind—not based on randomly chosen timelines or politically appealing slogans. Your committee has played a highly constructive role in holding robust examinations of these issues. We hope that all members of the Senate will take these facts into consideration in developing climate change legislation. Utilities such as PacifiCorp face growing demand for energy, and we must build some type of resource to meet this demand, as we have an obligation to serve. It is critical that as we continue to debate the future of energy supply for the United States, we don‘t forget our current customers, who expect to see a light come on when the switch is turned, while paying a reasonable cost to do so. Thank you. I would be pleased to answer any questions. The Chairman. Thank you very much. I‘m informed Senator Tester‘s going to have to leave in just a few minutes, let me defer to him, and he can ask my round of questions, and I‘ll come along later. Senator Tester. Mr. Chairman, I want to thank you very much for that. I want to—we‘ll kind of jump around here a little bit, Frank— the technology you talked about can be retrofitted on existing coal- fired plants, correct? Mr. Alix. Correct. Senator Tester. You said that the cost is about $20 per ton of CO2? Mr. Alix. Correct. Senator Tester. Now, I know it varies on the coal, but just how much CO2 is produced from a ton of coal from, say Wyoming or Montana? Mr. Alix. We look at more, in terms of a 500-megawatt plant is going to produce about 4 million tons a year of CO2. Senator Tester. Four million tons a year? Mr. Alix. Regardless of the coal. Senator Tester. Right. Mr. Alix. You know, to a certain extent, the coal, the carbon and the heat content are pretty closely related to CO2 release. Senator Tester. OK, the size availability, it will fit on any size plant? The retrofit? Mr. Alix. We don‘t see any reason why not. Senator Tester. It‘s 90 percent efficient? On capture?

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Mr. Alix. We‘re at lab scale today, but our lab testing which directly correlates, we think, to our next commercial scale up shows 90 percent capture is very doable. Senator Tester. OK, so, and what‘s the cost—any idea of what it costs to retrofit a plant? Of the size you talked? Mr. Alix. You know, we generally look at this $20 a ton, about $10 a ton is capital cost for retrofit. Senator Tester. OK. Mr. Alix. We‘re in $500-plus dollars a kilowatt for the retrofit. Senator TESTER. Five hundred a kilowatt—— Mr. Alix. So, let me put in numbers maybe you can understand. For a base loaded plant, you know, we‘re maybe $200 to $300 million to put it on a 600-megawatt plant. Senator Tester. OK, sounds good. Andrew, the technology you talked about that moves coal to natural gas, what‘s the sufficiency, BTU to BTU? Mr. Perlman. It‘s between—depending on the type of coal and the feed sock, between 68 and 72 percent efficient. Senator Tester. OK. Do you have a plant of any size? Mr. Perlman. We do. In Des Plains, Illinois—— Senator Tester. That‘s right. Mr. Perlman [continuing]. At the Technology Institute. Senator Tester. What kind of production does it have? Mr. Perlman. It‘s relatively small, it‘s about 3 tons per day of Power River Basin Coal. Senator Tester. Right. But you don‘t see any problem with increasing that production up? Mr. Perlman. No, it‘s a, basically a fluid-bed reactor, it‘s basically a tube with no innards. Senator Tester. Gotcha. Mr. Perlman. So, you know, the scale-up of fluid-bed reactors has been pretty well understood and modeled for—— Senator Tester. All right. Don, the oxy-coal process that you talked about—what is the cost per kilowatt, or megawatt or however you want to produce it, compared to a conventional plant now? Mr. Langley. I think the most relevant cost is we would say that it‘s between a 45 and 50 percent cost of electricity increase—— Senator Tester. OK. Mr. Langley [continuing]. To use oxy-coal, over a plant without it. Senator Tester. OK. Is there additional water needs with your process? Mr. Langley. No, not particularly. Senator Tester. For cooling? Not, huh? OK. Mr. Langley. I don‘t think, I think so. Senator Tester. OK. Good. Jim, first of all, I want to thank you for supporting my amendment. It‘s interesting what an organic farmer can combine with Dow Chemical on policy, but I really appreciate Dow‘s vision on that. Mr. Rosborough. Thank you.

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Senator Tester. You talked about a public/private partnership. The amount of money that is being allocated at this point in time, is it doing any good at all? Is it heading in the right direction? If you were a person in a position that could make a decision on how the money were to be allocated to form these kinds of partnerships, how would you do it? Mr. Rosborough. Senator, I think as you know in your amendment, there was a call for approximately $10 billion worth of direct loans, which is—to us—a fairly reasonable start for roughly three polygeneration types of complexes. It‘s our belief that the integration of chemicals, plastics, electricity and fuels, is necessary to maximize the carbon efficiency, and therefore get after the environmental friendliness of the feed stock issues, as well. Senator Tester. OK. So, $10 billion is in loans and that‘s how you would—that‘s how we‘d distribute it, is through a loan program? Mr. Rosborough. That would be a nice start, that‘s probably three major complexes. Our vision is, the first one would tend to be the most expensive and the least efficient, and by the time we get to the third one, we would have demonstrated improvements in both efficiency as well as technology. Senator Tester. Thanks. Finally, Bill, and I‘ll wrap this up very quickly, you talked about the economic impact of developing the technology. Mr. Fehrman. Right. Senator Tester. As I look at Montana that‘s on fire right now, we‘ve had—I don‘t know what the statistics are going to come back, but probably more 100 degree days in July than maybe we‘ve ever had before, it‘s been incredibly hot there, it‘s incredibly smoky right now, the growing season has completely shifted from when I was a kid. The question for me becomes, what are the economic impacts if we don‘t develop this technology? Mr. Fehrman. We don‘t argue the fact that we have to do something, my point on this is that as we go forward with these types of technologies, we have to bring the regulators who regulate us along with us. They are bound by statute to select the least-cost alternative. Until that sort of policy has changed in one way or another, then you‘re placing the regulators who are assessing our willingness to do these types of things at risk. In fact, in our case, we have a public partnership, public/private partnership in place, with the Wyoming Infrastructure Authority, where we are looking to do a demonstration project with IGCC. We have talked with some of our regulators and the fact that the cost of that is so significantly higher than the next alternative that we have today, they‘re not clear that they would allow those costs to go through to our customers. Senator Tester. Gotcha. I gotcha. Point well taken, thank you. Thank you, Mr. Chairman. Thank you to the other members of the committee. The Chairman. Thank you, Senator Domenici. Senator Domenici. Mr. Alix, I think it‘s fair to say that you have an optimistic prediction for the deployment of technologies capable of capturing and sequestering carbon dioxide, especially in cases where this can be done at existing plants. Do you have a timetable in mind for the point at which your company will be able to guarantee these technologies? Mr. Alix. We‘ve talked this over with our partners in building commercial designs, and estimates now, we believe that after the 100-megawatt-scale type unit, about 2012 is the timeframe we‘ll have that operating. We believe, in 2011, and within about a year of operation on a 100-megawatt-scale unit, we should be able to provide commercial guarantees there, consistent with all conventional pollution control equipment.

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Senator Domenici. Twenty eleven? Mr. Alix. Twenty eleven for the test, 2012 for the guarantees. Senator Domenici. OK. What is the response as you gather, of the companies to that kind of out-year assurance of guarantees? Mr. Alix. I think the initial reaction is quite a bit of skepticism, but once they get into the details of our process, and why we have confidence, and why we think the equipment‘s available to scale it, I think it becomes credible. Senator Domenici. Jim, let me ask you—I understand that Dow is a member of the United States Climate Action Partnership? Mr. Rosborough. That is correct, Senator. Senator Domenici. Which has called for mandatory limits on CO2 emissions in the United States. Current economic conditions have led to an increasing pattern of Dow and other manufacturers moving investment from the United States to China. In your opinion, would mandatory limits on carbon dioxide solely in the United States increase or decrease the trend in the world? Mr. Rosborough. Senator, thanks for the question. We look at it as an integrated problem, and therefore an integrated solution is necessary. We believe that action on emissions is necessary, and at the same time, incentives on new technology to stimulate alternative feed stock development in the United States, and its conversion to chemicals, and plastics, and fuels is the best way, overall, to go. We are a global company, and we have investments around the world that are made for a variety of reasons—both in low-cost Feedstocks, as well as where the high-growth markets are. China is clearly a market that we‘re going to invest in, in the future. Really, our interest here in the United States is let‘s revitalize our assets here, and let‘s reenergize the United States to become a growth market for the Dow Chemical Company, and other industry players again. Senator Domenici. One last question, and then I‘ll stick around. Will Dow incorporate carbon dioxide capture and storage when, and if, they construct coal-based chemical manufacturing facilities in China? Mr. Rosborough. Senator, another good question. We have a corporate goal to reduce absolute carbon dioxide emissions by a significant percentage over the next 15 years. I can‘t, right now, give you the exact number, but it‘s on the record, we‘ve stated that on our website, www.dow.com, we list that. The project in China will adhere to the rigid environmental standards that we set globally, because as a company that wants to lead the way in environmental stewardship, we feel it‘s necessary to demonstrate environmental stewardship even in places like China. Senator Domenici. I‘m not sure we can make you do that, obviously, that‘s overseas, but in a sense, you would cause a great deal of disbelief in your statements with regard to corporate activities if you went one way here, and another way in China in striking out at the same problem. That would put us in a very difficult position. Say, we were for climate change control, and we pushed it here, and you were working like beavers to get it done, and we had all of these things in our law that we changed, and we see your company over there in China, doing part of it, but not the tough part. The tough part you leave off, the easy one, you say, ―You don‘t have to do that,‖ to your Chinese partners, ―You‘re good without it.‖ You understand that‘d be pretty bad, right?

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Mr. Rosborough. Senator, I understand your point. The Dow Chemical Company has a global strategy, we believe that climate change is a global problem which requires a global solution. Senator Domenici. Thank you very much. That‘s enough for me, Mr. Chairman. Thank you. The Chairman. All right. Senator Corker.

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STATEMENT OF HON. BOB CORKER, U.S. SENATOR FROM TENNESSEE Senator Corker. Well, thank you, Mr. Chairman, and I appreciate you having this hearing. I think the testimony that all of you all have given has been excellent. You know, this September, I guess, we‘re going to be debating—I think, there‘s a possibility we‘re going to be debating carbon cap and trade programs, and I guess, to me, there‘s an opportunity for us to marry, if you will, the issue of energy security with the issue of climate change, if we do it the right way. I know that some of you have pointed out solutions. Also, I guess, there are issues of logistics and that is getting the gas piped to the right places, getting the carbon piped, or shipped, to the right places. But I wonder if you had any comments about if something‘s enacted, it might be in the very near future, and my biggest concern about it is, what do we do with coal? That‘s the one area that seems to me to be hanging out there, if you will, and very difficult for us to deal with in the short term. I know I‘ve only got a few minutes here, but I‘d love to have a short perspective on the kinds of things—forget the incentives that you‘ve talked about, but some of the things we ought to contemplate, if you will, in any kind of carbon cap and trade bill that might pass the Senate, as it relates to coal and timing. I‘ll let all of you say that, although I want to make sure I have the opportunity to ask two more questions, so be brief. Mr. Fehrman. Very quickly, my only response in this would be to ask that the level of implementation of a program generally matches the availability of the technology to meet it. Senator Corker. I guess, you know, of course, we had the Energy Department in several hearings ago, and they talked about commercial viability of sequestration at 2045, you all have obviously given a much shorter horizon on that, in some cases, but I think we have to look at it on a broad basis for it to make a difference, and I‘m just a little concerned about how we match those two together, and again, any editorial comments, I‘d love to have over the next 30 seconds. Yes, sir, Jim. Mr. Rosborough. Senator, in Dow‘s view, coal has to be in the mix for Feedstocks. It is known to have a CO2 footprint issue associated with it, but we believe there is also technology existing already that can advance that problem to a solution. I think enhanced oil recovery has been mentioned many times today. That‘s a good solution because it takes the CO2 and uses it for an economic benefit. Whenever that‘s possible, we should do that. Senator Corker. But that‘s, again, regional, I think. We have the same issues, in many ways, with carbon sequestration that we have with ethanol, and that is, it‘s produced

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regionally, but hard to get—I think because of the time, what I might do is ask that you all be available for some questions, because I think we have an opportunity, actually, to get it right, in many regards, if we think about it thoroughly. Let me just ask Jim one other question, I was interested in the ranking member‘s questions—would Dow be interested in a carbon cap and trade program, even if all of the allowances and credits were optioned on the front end? Mr. Rosborough. I think we‘d be interested in looking at it, because we‘re interested in creative solutions to a very complex problem. I couldn‘t commit that we‘d be interested in it and want to see it implemented without knowing more details about how it would work, and economic impact on the corporation. But, we‘re very open-minded to creative solutions. Senator Corker. No, just give me a judgment—a lot of the very sophisticated companies—and I would consider Dow to be one of those—certainly are crowding around all of us on cap and trade, because the sophisticated companies might get free allowances on the front-end, which is obviously very beneficial. The less-sophisticated companies, obviously will be out in the hinder lands, not doing so—how much of that is weighing in to some of the major companies coming here, and supporting—if you will—a cap and trade program, in your estimation, as an individual, not as an employee of Dow? Mr. Rosborough. It‘s hard for me to separate the two, but I‘ll say this—any project we look at, from now on into the future, contains with it a cost estimate dealing with the carbon footprint. So, we are planning that, from now on, any plant that we produce, or any plant that we build, will have a carbon solution that goes along with it. Senator Corker. Let me just ask one last question—I still have 14 seconds—thank you, Mr. Chairman. I really am interested in this, I think we have a tremendous opportunity to work together toward a good end. Some of you have talked about the initial base cost of carbon sequestration and some of you have talked about it on a per-ton basis. Our Chairman, here, has a bill that actually has a, sort of a, safety valve price of carbon per ton, and I‘d be curious for all five of you just to give me an estimate, as to what the price of carbon has to be, per ton, adding in the initial fixed cost the capital base you have to put in on the front-end—what does the price per ton have to be to make sequestration—let‘s say in the year 2018—viable to be competitive with some of the other Feedstocks and supplies? Just, give me a number. Mr. Langley. Thirty-five dollars a ton. Mr. Perlman. I think closer to $20 a ton. I just want to briefly comment on one thing. Senator Corker. OK. Mr. Perlman. I definitely think you should implement the programs, because we‘ve got an amazingly innovative country that‘s going to come up with technologies and solutions, and there‘s a venture capital community here that‘s going to fund them. So, if you implement a program, and you give people visibility, and it‘s the opportunity that technology will be there. Senator Corker. I really am very interested, I just want to make sure that we do things right, and I appreciate you saying that. I agree, we have an opportunity, innovatively, to do some things here in our country that could make us a leader, but we‘ve got to do it the right way. Yes, sir. Mr. Alix. I‘m in that $20 a ton ballpark. Senator Corker. Jim.

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Mr. Rosborough. I suppose my colleagues have bracketed it for me, and I have to say I don‘t really know the answer. We‘ve studied it a bit, but we‘ve looked at other studies, and they‘re sort of doing an average of the averages right now. It requires some specific due diligence on our part before I can answer your question, Senator. Mr. Fehrman. I agree with Jim. Senator Corker. So, the last two guys ought to run for the Senate. [Laughter.] Senator Corker. I would—thank you all—I‘m just kidding— thank you all very much for your testimony, and I hope that we‘ll be able to talk, talk to you all more in the future. Thank you very much, I appreciate it. The Chairman. Thank you all very much. Let me ask a question here—one of the issues that I can‘t quite understand, we‘re informed by developers of these new power plants that they cannot commit to deploying this new technology, unless they‘ve got a performance guarantee from the vendor of the technology, or at least that‘s sort of what I‘ve heard from some of them. It seems as though, I guess, Mr. Langley, let me ask you—you mentioned that your company‘s involved in developing a 300–megawatt oxy-coal combustion plant with CO2 capture. Does that mean that you have been able to issue a guarantee on this technology on that size plant? Was that not required or what? Mr. Langley. The plant had a—I‘ll say, a fairly unique structure. We did issue some guarantees, but they were limited in nature, so the risk of that project has been shared jointly between the providers and SaskPower Corporation. The Chairman. I guess this question of where the risk gets placed is key in all of this— how much of it is with the technology developer, how much of it is with the plant that‘s being constructed, I mean, the owner of the plant, how much of it is with the Government. Mr. Rosborough, you folks, in working, in supporting Senator Tester‘s bill—and I think, in your testimony today as well—call for a Government guarantee of 50 percent of the cost of the various gasification plants that you believe could be built. Why is a loan program superior to a guarantee of a loan? Mr. Rosborough. Thank you, Senator. The issue for us is, we‘re thinking about megabillion dollar chemical complexes, because that‘s sort of the way we do our business, we feel economies of scale are necessary to compete globally. So, you talk about an integrated site of, to $6 or $8 billion of a gasification-based technology, and compare that against a $2 or $3 billion conventional alternative investment. We look around at the investment banks available, and the kind of moneys necessary, from one single entity to make the kind of a loan, is actually getting problematic, and we think it‘s possible that you might develop a consortium of lenders that could do it. So, we‘re open minded to that. But we just think it‘s more feasible to consider a direct-loan program with the Government, where the money comes from the most secure entity that I can think of. The Chairman. You also talked about a consortium of industrial companies that would work in partnership with the Government to, essentially proliferate these gasification projects. Is that consortium pretty much in existence at this time? Or is that something that would have to be created, down the road—where are we with that? Mr. Rosborough. It is not in existence today, Senator, but it can be created down the road. I would say, given the priority that we‘re all putting on this subject, we‘d be able to create that fairly readily.

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The Chairman. Because I think about some other areas that are not particularly analogous, but I remember when the semiconductor industry came together, and essentially developed a proposal, and came to us—here in Congress, came to the Administration first, and said, ―We need to establish a Semi-tack,‖ and the Government put up half the money, and the industry will put up half the money and that will allow us to remain in the lead in the world in developing these new technology for semi-conductors. So, you‘re talking about something similar in this area, as I understand it, where industry would come together and agree to fund half of the cost of a major new industrial effort. Is that a correct interpretation of what you‘re saying? Mr. Rosborough. I think so, Senator, I think that‘s a fair assessment of a program that we‘ve got in mind. The Chairman. Can you do that—you know, a lot of what Dow Chemical does has nothing to do with coal-to-liquids. Mr. Rosborough. That‘s correct, Senator. The Chairman. You know, coal-to-liquids has become a bit of a difficult issue here in the Congress, and in our National debate, because of concerns about emissions. It strikes me, though, that what you‘re proposing, the main thrust of what you‘re proposing does not get us into coal-to-liquids. It is talking about industrial gasification projects to produce all sorts of useful products that clearly we‘re going to need going forward. Am I correctly interpreting that? Mr. Rosborough. Senator, that‘s correct. We think, I mean, our industry has been tied to fuels producers ever since it began. The by-products of fuels manufacturers are the Feedstocks for our company. A coal-to-liquids regime would, in fact, produce Feedstocks for Dow, but we don‘t think stopping at liquids is the most efficient way to go about it, we think that carbon maximization, carbon efficiency maximization requires you to take electricity, fuels, chemicals and plastics, and do them all together in one spot. The Chairman. OK. Mr. Rosborough. So we advocate a polygeneration kind of approach. The Chairman. Senator Domenici. Senator Domenici. Yes, thank you. Senator Bingaman, let me say, this is a very good opportunity for our committee to take a look and see if we‘re really interested in doing something, or if we want to do some more talking. But, I‘m not so sure that what we‘re presenting for our members to take, is well, before I finish that sentence, let me ask—would Dow be, at the offset, the most logical and perhaps most appropriate in the marketplace to do this? Or are we saying there would be more than them that could do it. It‘s just that they and others would have to get with it to propose this kind of efficiency. Mr. Rosborough. Senator, thanks for the question. The Dow Chemical Company has been integrated in the manufacture of chemical, plastics and electricity ever since our inception, so we have already been a practitioner of polygeneration. Senator Domenici. Right. Mr. Rosborough. In that regard, it puts us as a logical member of a consortium. Senator Domenici. Yes. Mr. Rosborough. We‘re happy to take a leadership role in something, because we also know how to operate, build and manage mega-projects. But, we‘re not coal experts, we‘re not

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carbon sequestration experts. We‘re not exactly on the cusp of some this new technology, as my friend, Mr. Perlman, for example, is. So, we believe a consortium of multiple, of multiple entities is important, and how it actually ends up getting led and managed, would be up to the members of the consortium, I think. Senator Domenici. I don‘t think, in the end, that it‘s going to be quite like the entity that was put together, that both you and I were involved in, with others, where we had a Secretary of Defense who many thought was a stubborn old ox, and it turns out, you all know who he was. He turned out to be, on these kinds of things, more right than wrong. He joined in making sure that the Department of Defense was heavily involved in this mix and match, so that America would take the lead in the world. Just takes us a couple of years to get there, and a lot of resources. Whatever the model that we would look at and say, this is what it is, it‘s fine with me. I think we have to start talking about how do we get there. You all have been doing some talking about how you get there, from what I see. That‘s good. We‘re not operating in a vacuum. I believe something like this must be done. It‘s a terrible vacuum, and it‘s going to be filled. We better get with it, or we won‘t fill it. You all are saying, to this group—not only is that true, Senator, but we‘re telling you that we know somebody will fill that, because it‘s too natural to not happen, right? It‘s going to happen. It‘s not a hard thing, it takes a lot of hard cash, you know—there‘s a lot of that around, too, just given the right project, right? It doesn‘t matter whether it‘s $6 billion or twenty—they‘re going to get the money, they‘re going to have the money, if you give them the right proposal, they‘ll find the money. So I want to say, Senator, I think we came together, maybe it was for a different reason, a little different. But I want to put my two cents up there that I don‘t know why we‘re going so slow on some of these. You‘ve admitted here for awhile that if you choose the wrong vehicle, you start off with a negative receptivity. We don‘t want that. We want to make sure that people like you and I can both be for this, right? Not that we fight, and saying we‘re not bored, we‘ve got to say that you and I and therefore, a rather large group of these people here, feel like this is really doing something for the country. It is doing something for the country. Because if we don‘t do this, and we let you all get away and don‘t do it, we‘re making a big mistake. If you all think you can you know, play games with us, and not be competitive, but just say, ―We know we‘ve got America here, they‘ve got to have us, and so we‘re going to take them,‖ well, that ain‘t gonna happen either. Because I think we do have enough smart people that it won‘t happen. Mr. Chairman, thank you, it‘s a good meeting and I learned a lot and I appreciate it. The Chairman. Thank you very much. Senator Barrasso. Senator Barrasso. Thank you, Mr. Chairman, I know the hour is late and others need to be places, but I want to follow up on a question you asked, Mr. Chairman, and I want to agree with my distinguished ranking member of this committee, Senator Domenici, and his comments. You know, we have 250 years of future for coal, there‘s so much in the United States, and Australia, and China, it‘s going to be used, and we need to develop the technology, and as rapidly as we can, to make sure that those energy resources are there, and we‘re less dependent on international and Middle East sources of energy.

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My question for Mr. Fehrman, and I appreciate what you do in Wyoming, and it‘s not just coal, I think I read a recent story about some wind generation and renewables and a commitment of your company to all of those things. But, I‘m especially impressed in your comments and in your testimony, talking about how PacifiCorp was chosen as the Wyoming Infrastructure Authority‘s partner to pursue the high altitude IGCC plant in the State, and designed to use the Powder River Basin Coal. You said you needed some of the Government‘s support on that. When the Energy Bill was passed—although I wasn‘t a member of this body, it said to me, the Government should be a player, a partner, and I don‘t think that the Government has come along to that degree. I read some of your comments about some of the things you need accelerated— depreciation, investment and production tax credits— do you have a timeline on some of those things? How much you need, for how long of a period of time? To make this specific program in Wyoming possible and doable, and get started? Mr. Fehrman. Thank you for the question. The key driver on the issue with the Wyoming Infrastructure partnership that we have is really tied to the section 413 dollars that are in the Energy Policy Act, and both the WIA and ourselves are looking for Government support to go through the funding mechanism to basically bring down the cost of this project, such that when we go to our regulators, the cost of the IGCC project will be neutral, or least cost, as compared to other alternatives, as to my earlier comment on the process we have to follow. So, we have laid out with the WIA the funding program, and essentially, the sooner we can get funds to support the project, the sooner we can begin. This is a case where we will not be able to invest significant development dollars into this program, until we have some sort of assurances that there will be the section 413 dollars coming through to help offset that difference in cost between various types of technologies. Senator Barrasso. Thank you, Mr. Chairman. I know the hour is late and you have other things to go to. I appreciate it. The Chairman. Thank you very much. I think this has been very useful testimony and we appreciate you all being here and giving us the benefit of your views. We may have some follow up questions, and if we do, we‘ll be in touch. Thank you, again, for your patience in getting us through this delay we had to put you through. Thank you. [Whereupon, at 12:28 p.m., the hearing was adjourned.]

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APPENDIX: RESPONSES TO ADDITIONAL QUESTIONS Responses of Frank Alix to Questions from Senator Bingaman Question 1a. We have been told by several witnesses in the past that, absent a price on CO2, there is no business case for capturing. What‘s different about your pilot project at the Burger Plant? Answer. Powerspan has venture capital investors who believe that a cost effective system to capture CO2 from existing coal-fired plants may be highly valued in the future. They are motivated to invest in our pilot project based on expectations of a return on their investment. Question 1b. What‘s FirstEnergy‘s incentive to take on the additional costs? Answer. FirstEnergy is an investor in Powerspan and also has several coal-fired plants that would benefit from a cost-effective CO2 capture solution, should power generators face CO2 emission limits in the future.

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Question 2. Your technology is particularly attractive since it may be adaptable to the existing fleet. How extensive do you imagine such a retrofit would be at a typical PC plant? Answer. The retrofit for our ECO2 system would be similar in scope to a wet scrubber retrofit installed for SO2 reductions. Question 2b. Do most plants have sufficient space and a configuration that would accommodate retrofit? Answer. Most plants would have sufficient space and a configuration to accommodate a CO2 capture retrofit, however the degree of difficulty and associated cost of plant retrofits would likely show a large variation.

Responses of Frank Alix to Questions from Senator Corker Question 3a. As the Senate prepares to debate cap-and-trade legislation this fall, please give me your perspective on how we should contemplate and deal with coal in the short-term during that debate, apart from the incentives that you laid out in your testimony. Answer. Powerspan recognizes the need to provide for certainty regarding CO2 emission reductions, but also the wisdom of a cap and trade approach, which incentivizes the lowest cost solutions. Question 3b. Keeping in mind the need to rely on coal as part of our future energy mix, what do you think are appropriate emissions targets in what amount of time, such that we challenge industry without being unrealistic based on what is technologically possible? Answer. Powerspan does not have a specific position on CO2 emission targets or timing since once technology is available, such a decision is largely an economic tradeoff of cost against perceived climate change risk. Meaningful CO2 emission reductions from coal plants in the short term—i.e. 5-10 years-are probably not viable because required CO2 capture and

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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.

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Question 2. How do you control conventional pollutants such as sulfur dioxide and mercury that are generally produced from constituents in coal? Answer. The gasification process does not produce sulfur dioxide but rather hydrogen sulfide which is easily removed from our product gas stream and converted to saleable elemental sulfur. Any volatilized mercury is captured in an activated carbon bed and can be safely disposed. Question 3. You envision capturing the CO2 from the process of deriving your natural gas equivalent; do you have any similar plans to capture CO2 from combustion of the gas for power generation? Answer. Great Point‘s process produces synthetic natural gas, which has the same basic chemical composition as natural gas, or methane—CH4. Because coal contains a higher ratio of carbon to hydrogen than natural gas, the carbon that Great Point will capture in its process is the excess carbon, above and beyond that contained in the CH4, that would otherwise be released to the atmosphere as carbon dioxide if coal were burned in a conventional coal-fired power plant instead of being gasified. Great Point‘s process, which produces CH4 and allows capture of the excess CO2 from coal, does not in itself involve combustion of CH4 for power generation, nor would Great Point own or operate gas-fired power plants. Great Point is a fuel supplier. The CO2 that is produced when CH4 is burned (by others) for power generation is not currently captured by any commercial technology, although post-combustion capture technology is actively being worked on by many (other) companies. However, because burning CH4 for power generation produces so much less CO2 than burning coal for power generation, a power plant that emits no more CO2 per megawatt hour than a combined cycle natural gas-fired power plant is considered to have a good carbon footprint, not a bad one. The CO2 emissions per MWh of such a plant currently represent the standard (or limit) for purposes of the new Emissions Performance Standards (―EPS‖) recently adopted as a progressive, climate-friendly measure by California, Washington, and other states. By making more fuel available for this comparatively climate-friendly method of power generation, Great Point will be contributing to lower power sector CO2 emissions overall.

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Responses of Andrew Perlman to Questions from Senator Sanders

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In your written testimony, you are very enthusiastic about the prospects for your company‘s technology, which will convert coal to cleaner natural gas utilizing catalysts instead of conventional coal gasification technologies, which are much more complex. You mentioned that you have significant financial backing and suggest that your first major project will be online by 2011 or 2012. You testified that your company would be in a position to give vendor guarantees by 2012, so that the technology could be readily purchased on the commercial market. This sounds very promising especially as other witnesses did not project this kind of progress with their ideas until 2020. Question 4a. Why then, do you suggest that it would be useful to your company to be eligible for a 50 cent per gasoline gallon equivalent production tax credit for the generation of this natural gas? Answer. We are just as enthusiastic about our prospects for commercial success as your question suggests. The value and importance of the proposed production tax credit for the energy output of our technology, while still in its early stages—and the logic supporting such a credit—are precisely equivalent to those that support credits for other relatively new (although by now significantly older) climate-friendly energy technologies, such as wind energy and biofuels production. In summary, new technologies, even when first deployed at commercial scale, typically debut with somewhat higher costs and less perfect performance than they will attain once they have greater operating and design experience, can be optimized and ―tuned,‖ and can enter into larger-scale production of greater numbers of units and thereby reduce average costs. There are also substantial ―pioneer‘s penalty‘‘ risks for investors, lenders, and early adopters, as well as the company itself, during the period when the technology is still relatively new at commercial scale and relevant infrastructure is not yet fully developed. A production tax credit is a tried-and-true method of stimulating early adoption of climate-friendly new energy technologies in the face of such initial hurdles. Question 4b. Do your financial projections suggest that you will not be able to make a profit without this credit? Answer. No, but the primary concern at this stage is necessarily how best (and most quickly) to attract equity investment and necessary debt from private capital markets, in order to speed the construction of production facilities. For the reasons set forth immediately above, and as demonstrated by the experience of wind energy, the production tax credit makes it far easier to attract both equity investment and lenders for large-scale commercial deployment of new energy technologies in their early years. There are more risks and initially higher costs associated with new technologies in their earlier stages than will be the case in later years, and the PTC is one method of reducing such risks and helping ―level the playing field‖ for desirable new technologies in the stage when they naturally involve initially higher costs than established alternatives. Question 4c. At what price do you expect to be able to sell your natural gas in 2011–12? What do you project the cost of conventional natural gas to be at that point?

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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.

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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

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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.

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Question 6. For some time now, the price of natural gas has been very volatile. Would you expect the price floor you mentioned to be established in such a manner that when the price of natural gas was below the price floor, the government would provide funding to your company to reach the price floor, and conversely, when the market price was above the floor, that this funding would be paid back to the government? Or would it be more advisable to establish a long-term (multi-year) calculation of the market price to determine if it would be below or above the price floor? Answer. We would be happy to work with the Committee to help design a price floor program the Committee considers reasonable and feasible. Many variables are involved, and many possible approaches could work. For example, the price floor protections might be triggered only after natural gas prices had remained below synthetic natural gas production costs for a specified period of time. Or the protections might be made available to those who purchase the synthetic natural gas at contract prices, such as electric utilities, rather than to the producers of synthetic natural gas such as Great Point. If the price floor provisions of such a program actually resulted in money changing hands, and if Great Point itself, as a producer, actually received any of that money, then of course Great Point would expect that the program would be designed in such a manner that money might also be paid back to the government if sales prices for synthetic natural gas exceeded some specified level. That would be appropriate and fair. Again, Great Pont would welcome the opportunity to help the Committee design a program satisfactory to the Committee in all respects.

Response of Andrew Perlman to Question from Senator Corker Question 7. As the Senate prepares to debate cap-and-trade legislation this fall, please give me your perspective on how we should contemplate and deal with coal in the short-term during that debate, apart from the incentives that you laid out in your testimony. Keeping in mind the need to rely on coal as part of our future energy mix, what do you think are appropriate emissions targets in what amount of time, such that we challenge industry without being unrealistic based on what is technologically possible? Answer. We believe that, in general, the so-called ―California‖ emission performance standards (―EPS‖), recently adopted in California and Washington, among other states, are appropriate for power generation facilities. Basically, these particular EPS establish emissions targets per megawatt hour of power production based on the CO2 emissions of efficientlyoperated 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

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Washington have made provision for the applicable standard to become tighter and lower as average natural gas fired power plant emissions are reduced. Natural gas-fired power plants can meet these standards by using synthetic natural gas from Great Point Energy and other producers. For coal gasification power projects to meet these standards, some form of carbon capture and storage (―CCS‖) will be necessary. Enhanced oil recovery (―EOR‖) can provide an appropriate transitional form of CCS in localities where EOR opportunities exist, provided reasonable oil field management practices for CO2 are followed. Both CCS and EOR are currently technologically possible. (Even geological sequestration of CO2 appears technologically possible, although currently rather costly.) For coal combustion power plants to meet these standards, post-combustion capture technology as well as CCS would also be required. Great Point is not the best source of information for the Committee on when post-combustion capture is likely to be considered technologically possible.

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Response of Bill Fehrman to Question from Senator Bingaman Question 1. You mentioned that for resources planning purposes PacifiCorp estimates the cost of CO2 at eight dollars per ton. What led you to that number? Have the various bills introduced in Congress assigning prices to CO2 caused you to revise that estimate? Answer. Beginning in 2002, PacifiCorp looked at a variety of externally available data, including: (1) the current greenhouse gas offset market, including offset investments made by The Climate Trust established by Oregon law, (2) existing greenhouse gas markets in the United Kingdom and the European Union, and (3) U.S. macroeconomic analyses of scenarios involving limits on greenhouse gas emissions. At the time the analysis was done, the offset market yielded estimates at the low end of the range and helped the company define a low sensitivity of $2/ton of carbon dioxide. The existing overseas markets were operating in the range of $8/ton. Public comment on the value to use has been sought as part of each subsequent Integrated Resource Plan and ultimately resulted in the use of $8/ton for our models Regarding its current adequacy, the company now believes it to be on the low side based on legislative developments. Question 2. The MIT report, and others, have pegged $30 per ton as the price that would drive utilities to capture and sequester CO2. Do you generally agree with this estimate? Answer. Technology, costs and regulatory environment associated with CO2 capture and sequestration are as yet undefined. Therefore, it is hard to conclude exactly what would happen at $30 per ton. Question 3. We talked a bit about the order in which additional power is ―called up‖ to meet demand, with the effect being that lower CO2-emitting natural gas generation is used less due to high natural gas costs. Do you have an opinion regarding the potential effects on energy prices and technology deployment if some regulatory mechanism were put in place to mandate increased use of lower-emitting generation?

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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.

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Responses of Bill Fehrman to Questions from Senator Domenici Question 4. Mr. Rosborough describes gasification as ―technologically proven‖ in his testimony, and yet you assert the opposite. Your statement maintains that, ―IGCC is not a commercially viable technology at this time.‖ Is that statement based on the fact that adding turbines to the back end of a gasification unit is significantly more complicated than the processes undertaken by Dow and other chemical manufacturers, or is it a result of significantly different levels of experience in your respective industries? Answer. We regard ―technologically proven‖ and ―commercially viable‖ as two different things. For a regulated utility to adopt new technologies on a broad basis, equipment needs to be economically reasonable, available to meet specific performance guarantees, and operable as a utility dispatched asset. Current cost estimates relating to this technology show it to be significantly more expensive when compared to other generation options. IGCC refers to the integration of the gassifiers with the power block to gain efficiencies in the electrical generation process. While this integration adds efficiencies, it also adds complexity and is unproven at a commercial level.

Response of Bill Fehrman to Question from Senator Corker Question 5. As the Senate prepares to debate cap-and-trade legislation this fall, please give me your perspective on how we should contemplate and deal with coal in the short-term during that debate, apart from the incentives that you laid out in your testimony. Keeping in mind the need to rely on coal as part of our future energy mix, what do you think are appropriate emissions targets in what amount of time, such that we challenge industry without being unrealistic based on what is technologically possible? Answer. On March 20, 2007, MidAmerican Energy Holdings Company chairman and chief executive Officer David Sokol testified before the House Energy and Commerce Subcommittee on Energy and Air Quality, at which he outlined the company‘s position on global climate change. Mr. Sokol told the Subcommittee the nation needs a phased-in technology and policy-driven approach to provide tools necessary to successfully reduce

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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- 20 19), the company believes climate policy should focus on technology development and market transformation activities. In the electricity sector, MidAmerican proposed the following measures: 1. 2. 3. 4.

Adoption of a flexible renewable energy portfolio standard. More stringent energy-efficiency mandates. Policies to encourage efficiency improvements at existing facilities. 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.

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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 fiveyear period through 2050. Mr. Sokol concluded his testimony with five points he said lawmakers should thoughtfully address in any global climate change legislation. 1. The electric industry cannot change past decisions and should not be penalized for past fuel choices. 2. The feasibility and cost of clean energy technologies must be known before they are deployed, because utility companies and regulators have a responsibility to keep customers‘ rates as low as possible. 3. A recommitment to funding research and development in the energy sector must occur. 4. Failure to take technology development timelines into account could result in unintended consequences, such as fuel shifting from coal to natural gas, which already faces tight supply-demand constraints. 5. A cap and trade concept in itself will not reduce emissions, bring new technologies on-line or reduce prices for renewable resources. This complex issue cannot be solved that simply.

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Responses of Jerry Hollinden on Behalf of the National Coal Council to Questions from Senator Bingaman

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Question 1. The National Coal Council report advocates for significantly increased funding for R&D and demonstration projects. Do you envision that this will be primarily a federal government undertaking or an effort more akin to FutureGen or some other model? Answer. In all of its reports to the Secretary of Energy, The National Coal Council has consistently advocated the need for public/private partnerships on major R&D and demonstration projects. This goes all the way back to the initial Clean Coal Technology program of the late 1980s. The combination of public support in the form of both money and policy, with that of private industry in terms of money, siting of project facilities and technology development have yielded dramatic acceleration in bringing the various technologies to the market place. The Council continues to support these types of collaborations. The Council has also consistently supported FutureGen since its inception, and the current report continues that support. Other examples of public/private partnerships supported in the Council‘s report include the Carbon Sequestration Regional Partnerships, the Carbon Sequestration Leadership Forum, the Asia-Pacific Partnership Program and the Clean Coal Power Initiative. While each of these efforts has a different combination of public and private input, they, along with many other similar efforts, all are examples of this kind of partnership. The Council does not favor one over any other and in fact supports them all. In summary, the Council believes that the best way to expedite getting technologies from the R&D phase to the market place is through a joint commitment by both public and private leadership. Question 2. Your Report echoes the MIT report in recommending undertaking on the order of 5 large scale sequestration projects. Given the significant amounts of CO2 required for a demonstration on this scale, where would such a project likely get the CO2? Is it reasonably likely anyone would be capturing CO2 at the scale necessary absent some new kind of specific incentive to do so? Answer. While The National Coal Council does have a member who is an emeritus professor from MIT, the full Council arrived at its recommendations independent of any of the MIT work. The recommendation for 5 major projects was a best estimate by the Council. It may be necessary to conduct more projects than 5, depending on the types of capture, transportation and storage technologies developed as the R&D effort progresses. The estimate was not meant to be a goal, but was meant to recommend that the necessary number of projects be completed in an effort to bring the largest menu of options to the market place so that carbon capture and storage could be achieved at the lowest possible cost and also to reduce risk, which may be even more important. As for the availability of sites for these projects absent a new kind of specific incentive to capture and store carbon emissions, the charge received by the Council from the Secretary of Energy was to ―conduct a study of technologies to avoid, or capture and store, carbon dioxide emissions—especially those from coal based electric utilities.‖ The Secretary did not ask the Council to investigate any incentives, new or old, for capturing CO2, and therefore, the Council did not make this a part of the study. However, in the very first paragraph of the

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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.

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Responses of Jerry Hollinden on Behalf of the National Coal Council to Questions from Senator Domenici Question 3. Climate change is a global problem. I fear that a number of proposals to address this issue will merely result in fuel-switching, or some other undesirable path forward. It is clear that other countries, particularly developing countries, will continue to consume coal in increasing amounts. In the absence of a binding international agreement, what clean coal technologies are developing countries likely to find desirable? Will developing countries have a preference towards efficiency improvements, oxygen-fired combustion, gasification technologies, or some other category that we can assist in the commercialization of? Answer. The Council report spent a considerable effort discussing the international energy market place. New and major players in this market place include China, India and some of the countries in Southeast Asia. The demand for energy will continue to increase dramatically as these countries continue to grow and develop. Each will develop their own energy resources and most of them have large coal deposits. Just looking at China as an example, they plan to increase their coal production from 1.7 to 3.2 billion tons per year by 2020. They intend to build 50 facilities to produce syngas from millions of tons of coal each year to fuel their industrial and agricultural sectors. They are planning to spend $20 billion on coal-to-liquids facilities in the next 7 years, and they are planning to build over 100 GWs of new coal- based electricity generation during that time as well. Other developing countries may not grow as dramatically, but they will grow and they will need clean coal technologies if they are to develop their coal resources. Each country will select the technologies that best fit their needs. Therefore, development of a wide array of technologies will best allow the U.S. to participate in this technology market place. Because of this, the Council has always supported a wide variety of R&D projects including more efficient electricity generation technologies as well as emissions control technologies. Oxy-firing, gasification and liquefaction as well as carbon capture and storage technologies should all be expedited for use both here at home and in the energy market place abroad. Question 4. I am concerned about the availability of technology, regulatory shortcomings, infrastructure sufficiency, and liability as it relates to carbon dioxide capture and storage. Do you believe we should deal with those issues before mandating carbon dioxide capture and storage, or including it as eligibility criteria for federally supported R&D projects? How do you suggest we best address those issues?

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Answer. The Council‘s report speaks to all of these issues. The technologies to capture carbon dioxide, while still in their infancy for the size and scale needed at generation plants, are the most advanced. Progress is being made because this has been the initial area of focus for R&D. However, the industry is still many years away from having proven capture technologies that could be applied commercially. There is currently no transportation infrastructure for moving carbon dioxide from the point of capture to the potential point of storage. This may require a whole new industry to be developed in order to be achieved. Transportation technologies are way behind the capture technologies. Storage of CO2 is being achieved on a small scale in regions of the country where it can be used for enhanced oil recovery. Because of this effort, storage issues are better understood. However, the scale at which these technologies will be needed for the volumes at which CO2 will need to be stored is incompletely understood at this time. All of the candidate geological configurations must be tested, as well as have the necessary monitoring data developed to ensure no leakage occurs. Finally, on the question of liability the Council has recommended that the Secretary work to determine the legal liabilities associated with carbon capture and storage. This includes resolving ownership issues and responsibility for stored CO2 in the event of leakage, and the implementation of long-term monitoring at storage facilities. The Council was not asked to address the issue of eligibility criteria for federally supported R&D projects, but it is clear that there is a need to develop technologies to address each of these issues. Question 5. It seems to me that efficiency improvements allowing generators to get more electricity out of the same amount of coal would be in their financial interest to pursue. Can you explain the disconnect that exists in this regard, and why plants have not maximized efficiency throughout the fleet? Is it because the savings associated with an efficiency upgrade do not justify the costs of the undertaking? Are there regulatory hurdles to pursuing these tasks? If so, please identify them for us. Answer. In May of 2001 the Council produced a report at the request of then-Secretary of Energy Bill Richardson (subsequently submitted to his successor, Secretary Spencer Abraham), that identified technologies that at the time could increase the amount of electricity from the existing fleet of coal plants by 40,000 MW. The approach set forth in those recommendations is still viable today, although several of those options may have been implemented already. These efficiency gains can be made at various points within the plants. They include steam turbine blade upgrades, improvements in condenser systems, and in the milling systems to grind the coal. In addition, the use of coal cleaned to higher quality levels can increase plant efficiency. The full suite of recommendations can be found in the study, ―Increasing Electricity Availability from Coal-Fired Generation in the Near-Term‖ available on the Council web page at www.nationalcoalcouncil.org. Plant efficiency upgrades are a practical, quick and less expensive way to reduce CO2 emissions in the near term as well. Given current clean air regulations, however, many power plant owners would not initiate helpful upgrades because of concerns that such improvements would trigger requirements for more expensive upgrades under the New Source Review program. Dialog between DOE and EPA on how best to achieve progress on this issue was

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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

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Question 1. The FutureGen government-industry partnership will demonstrate a number of important technologies but, as you mentioned in your testimony, there are a number of other technologies that will need similar demonstrations at commercial scale. Presuming they can‘t all be demonstrated through similar partnerships, can you give us some examples of alternative pathways to commercialization of advanced technologies? Answer. In addition to the Department of Energy‘s (DOE‘s) FutureGen partnership, the most logical route to the commercial-scale technical and economic validation of developing technologies is through DOE‘s Clean Coal Power Initiative (CCPI). The CCPI program is unique to DOE in that it requires a minimum 50% participant cost-share, and a Repayment Plan based upon the public‘s sharing in any profits derived from commercialization of the technology demonstrated, with the objective of full-cost recovery of the entire amount of our project investment. Question 2. Can you give us a sense of where you believe the state of the art to be in coal-fired generation and where you expect it to be in 10 years? Assuming a CO2 price on the order of the MIT Future of Coal report and increased RD&D support, when do you think we may reasonably be able to deploy a variety of near-zero CO2 emission technologies? Answer. Today‘s state-of-the-art for coal-fired generation in the U.S. is supercritical pulverized coal combustion. Additionally, there are two existing commercial Integrated Gasification Combined Cycle (IGCC) plants, originally designed for coal, that are presently operating on petroleum coke and pet-coke/coal mixtures. In 10 years we expect to see coalbased 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 report9, 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. 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.

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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.

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Question 3a. Can you quantify these increases for us, both for next-generation plants as well as traditional designs? Answer. New traditional plants are being adversely impacted by increases in costs, resulting from the lack of availability of materials and the lack of availability of skilled construction labor. Next-generation plants are likewise impacted by similar increases, and are further impacted by the costs of insurance associated with the requirement for performance wraps or guarantees that accompany the inherent risk of deploying new and unproven technology (current estimates for a next-generation IGCC plant performance guarantee are on the order of 35% of total plant construction cost), as well as the increased costs of construction associated with building redundancies into new plant designs to ensure defined plant performance and economic targets can be met. Furthermore, advanced coal plants, including IGCC and pulverized coal (PC) based systems with carbon capture, will require operations and maintenance personnel with significantly different skill sets, compared to those that support traditional facilities. Over the past 5 years, it is estimated that the costs of traditional pulverized coal combustion plants have gone up in the neighborhood of 75% to 100%, from approximately $1,200/kWe to approximately $2,000 to $2,500/ kWe. Over the past 5 years, it is estimated that the costs of next-generation coal-fueled plants have gone up in the neighborhood of 200% to 250%, from approximately $1,500/kWe to approximately $3,200/kWe (recent Duke Power IGCC estimate) to $3,700/kWe (recent AEP IGCC estimate). Question 3b. Are advanced clean coal plants disproportionately impacted by this trend of increasing costs? Answer. Yes, as a consequence of the need for both performance guarantees and risk mitigating redundancies, as explained above. Also, acquiring operations and maintenance resources with appropriate education and skill sets will result in higher personnel costs compared to traditional designs. Question 4. Can you quantify for us the costs of construction for a plant with the best environmental technologies that are currently available at commercial scale as they compare to ultra-supercritical plants and other advanced plants that would, in fact, incorporate some form of carbon dioxide capture and storage? Answer. NETL recently published a baseline study forecasting the ‗‗overnight‖ construction costs of power plant technologies that could be built and operated in the 2012 to 2015 timeframe.10 The information presented here is derived from the results of this study. Today‘s best estimate of the overnight construction cost for an ultra-supercritical coalfueled 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

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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, projectspecific 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.

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Responses of Jeffrey N. Phillips to Questions from Senator Bingaman Question 1. You give a hopeful picture that ―learning-by-doing‖ in a commercial setting will lead to significantly reduced costs over time for technologies. Are there any inherent incentives for private actors to lead in deploying new technologies? Are the efficiency gains and increased certainty regarding future regulation ever enough to push for leading edge design on their own? Answer. In short, the general answer is ―yes,‖ but in the case of carbon capture and storage (CCS), a combination of private initiative and public sector incentives is likely to be the most effective means of achieving the necessary design advances in a timely manner. Cost reduction through ―learning by doing‖ is real, as evidenced by the industry‘s history with other environmental controls, but in the case of SO2 scrubbers, for example, regulatory requirements were clear, first through the Clean Air Act‘s New Source Performance Standards and later through the Acid Rain provisions of the 1990 Clean Air Act Amendments. With respect to greenhouse gas (or CO2) emission regulations, while their prospect seems clear, their nature and timing are still big unknowns. Getting initial installations of advanced technologies in place, before regulations take effect, to start the learning-by-doing process—getting costs down before large investments are required for compliance—will take ―beyond market‖ incentives. The Energy Policy Act of 2005 sought to address this, but even some projects that had been awarded investment tax credits have recently been shelved due to regulatory uncertainty risk for CO2.

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Other ―institutional factors‖ and traditions have made the power industry prudent with respect to investments in not-yet-proven technologies. For example, policies in some states prohibit public utilities commissions from allowing cost recovery on investments in emission controls exceeding the requirements of current regulations. Also, coal has historically been a relatively inexpensive fuel in the United States, which has limited the amount of capital investment and risk that could be justified for unproven high-efficiency technologies. Further, the economics of power generation (and public scrutiny) always place a high premium on reliability. Because the reliability of a new technology is difficult to predict in advance of real-world application, there is an incentive to be the ―second in line‖ when it comes to buying new technology. Thus, in EPRI‘s opinion, leading-edge designs such as the extremely efficient pulverized coal plants with integral CCS outlined in EPRI‘s UltraGen Initiative, and the new generation of integrated gasification combined cycle units suitable for (or with) CO2 capture, will not be easy to implement without industry and government risk sharing. Programs such as the Department of Energy‘s Clean Coal Power Initiative can help spread risk and may ―tip the scale‖ in favor of new technology investment. By encouraging collaborative funding of demonstration projects, EPRI also helps spread the risk of testing new technologies. Each power generator contributes a small fraction of the total cost, yet receives the knowledge gained from the tests. Regulatory flexibility during the period of new technology introduction can also help. An example of success in this area was the incentives for early adopters of selective catalytic reduction (SCR) systems for NOX control. ―Allowance banking‖ and other provisions encouraged several power companies to install SCR units before the mandatory compliance date, allowing them to resolve reliability and performance issues (such as the unexpected problem of catalyst plugging by large-particle ash) while they could still legally turn off the units during normal operations. Question 2. In your description of your proposed UltraGen Project, you include the option of capturing 25% of the CO2 from the plant. Why only 25%? Why wouldn‘t you capture more CO2 in this project? Answer. Please allow me to clarify that we propose capturing 90% of the CO2 from 25% of the flue gas at a new, large (800 MWe net) clean and eficient pulverized coal plant. Capture of 90% of the CO2 from the inlet flue gas is the goal of the Department of Energy and many technology developers. Treating 25% of the gas flow from a very eficient plant (equivalent to 200 MWe) corresponds to a volumetric flow rate equal to the expected rating of an early commercial post-combustion CO2 capture module. Thus, choosing to treat 50% of the gas flow would mean testing two of the same modules rather a single larger ―more commercial‖ module. As a result, the research value would be only marginally improved while the cost of the CO2 capture demonstration element would nearly double. Were adequate funding for two test modules available, a better research strategy would be to put them on two different plants using different coals (and UltraGen is open to this possibility). Further, the scale-up to a 200 MWe CO2 absorber module represents an ambitious challenge in its own right. The largest post-combustion unit in current operation captures 500 tons of CO2 per day (from a steam reformer used in the production of urea fertilizer). About 200 MWe worth of flue gas from our proposed UltraGen I unit corresponds to more than 4000 tons of CO2 per day, an eightfold increase. We will use an advanced amine solvent to reduce energy penalties, and demonstrate thermal integration of the solvent reboiler (the step that

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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 oxycombustion CO2 capture). Question 3. In your analysis of the technical potential for emissions reductions from CO2 capture and storage, did you include retrofits of existing plants for CO2 capture and storage? If not, why not, and what would be the impact if we did? Answer. The economics of CO2 capture are best on plants that operate at high capacity factors (i.e., baseload). As new coal plants come on-line, they are dispatched in baseload mode while some existing plants are moved to load-following service. Thus, EPRI‘s ―Prism‖ analysis assumed all new coal plants coming on-line after 2020 would be the first to be built with CCS. Given differences in the generation mix serving regional grids and the likely variations in the compliance strategies ultimately adopted by U.S. power generators in response to CO2 regulations, we expect that some existing units may be retrofitted with CCS. But because costs for retrofits are higher and energy penalties greater, to be conservative in the Prism analysis, we assumed that existing plants underwent efficiency upgrades but not conversion to CCS. Research by EPRI and others suggests that retrofitting CO2 capture equipment to existing coal plants not originally designed for such systems would be very costly, ranging from ―considerably more expensive‖ than the incremental cost of incorporating CO2 capture equipment in new plants up to situations where it would be prohibitively expensive (virtually impossible) due to lack of available space in the plant. With respect to the latter, up to 6 acres at the back end of the plant is needed for a 500 MW unit. In addition, the energy impacts (in terms of output and efficiency reduction) are greater for retrofits than for new plants. EPRI has not conducted a plant-by-plant analysis to ascertain the number of existing units that could, in theory, be converted to CCS, and thus cannot estimate the CO2 emissions reduction potential (or cost and capacity reduction) of such retrofits. Instead, EPRI‘s analysis of the potential CO2 emissions reductions from CCS focused on the incorporation of CO2 capture into the sizeable new fleet of advanced coal plants (as projected by the Energy Information Administration) built to the growth in electricity demand. Question 4. We talked a bit about the order in which additional power is ―called up‖ to meet demand, with the effect being that lower CO2-emitting natural gas generation is used less due to high natural gas costs. Have you done any analysis to determine the potential effects on energy prices and technology deployment if some regulatory mechanism were put in place to mandate increased use of lower-emitting generation? EPRI hasn‘t conducted such an analysis for today‘s generation mix, but as part of the background pap er for the EPRI 2007 Summer Seminar, ―The Power to Reduce CO2 Emissions: The Full Portfolio‖ (see http://epri-reports. org/ DiscussionPaper2007.pdf), EPRI ran scenarios for 2050 in MERGE, a general equilibrium economic model used for analyzing the cost of CO2 emissions mitigation. Although this isn‘t a dispatch model, it can be used to estimate the composition of the generation mix and wholesale price of electricity when various potential solutions for reducing CO2 emissions are allowed or not allowed. The most

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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 coalbased plants in California at about $50 per metric ton when a modest contingency for first-ofa-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?

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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 base- load advanced coal plants with CCS (including the efects of a modest transportation distance and injection) having eficiencies exceeding those of the current fleet average. Of course, this won‘t happen automatically. A sustained, accelerated RD&D program involving private and public sector stakeholders will be required to bring the promise of ultra-eficient clean coal plants with CCS to commercial fruition in a timely manner. Existing research programs and roadmaps by DOE, EPRI, equipment suppliers, industry groups such as the Coal Utilization Research Council, and others provide the foundation for the necessary collaborative and proprietary efforts. In calculating the efficiency penalty for CO2 compression, EPRI assumes the use of an interstage-cooled compressor with a final delivery pressure of 2200 pounds per square inch (psi). This impact is typically reported in combination with the efficiency penalty for capture because both take place within the plant boundary. The efficiency impact of transportation depends on the distance the CO2 must be shipped and the diameter of the pipeline. Unless unusually long distances or undersized pipelines are involved, the impact is typically small relative to the energy penalty for capture and compression. Similarly, the additional energy requirements for injection are small given that pipeline delivery pressure is already at 2000+ psi. Question 7. You testified that you predict only a 10% increase in the cost of electricity by 2025 if carbon is captured and stored. Does this estimate include just the capture of CO2 or the full capture, compression, transportation, and storage? Please allow me to clarify that EPRI‘s goal for post-combustion CO2 capture is an energy penalty of no more than 10% and a levelized cost-of-electricity increase of no more than 20%. This reflects the cost of CO2 capture and compression, but not the cost of transportation and storage because these can be highly variable depending on how far a power plant is from a storage site and the permeability of the target formation. Transportation and storage could add another $5/MWh or more to the levelized cost-of-electricity. Question 8. You also mentioned that if liquefied carbon dioxide is not cleaned of sulfur or other contaminants before it is stored underground, it may clog up the pores in the underground rock, so that, instead of a 30-year storage capacity, you may only get a five-year storage capacity. Can you explain at what levels of contamination this is likely to occur? Does it depend on the kind of rock or saline substrata that the CO2 is being sequestered in? Answer. Although there is currently some uncertainty over the impact of CO2 impurities on subsurface rocks during injection and over the course of long-term storage, and further research is warranted, the scenario of plugging to the point that injection was no longer possible, as posed in the question, is not considered likely by researchers at Lawrence Berkeley National Laboratory.

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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 reprecipitate 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.

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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 longterm 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

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portfolio of generating resources—including new state-of-the-art coal plants—is our best strategy. Domestic resources including nuclear, renewables, and fossil fuels (particularly natural gas and coal) as well as imported resources like liquefied natural gas and oil will play different roles in different parts of the country. Coal is our largest domestic fuel resource, it provides over half our electricity today, and we project that it will be needed to provide affordable power in the future. Today‘s new coal plants are more efficient and much cleaner than older units and produce less CO2/MWh. EPRI studies have shown that without both new coal with CCS and nuclear power in the portfolio of solutions to the challenge of CO2 reductions, wholesale power prices will more than double and the U.S. economy will shrink (relative to its size with the full portfolio of CO2-reducing technologies) by $1 trillion. Question 10. As we look at the existing fleet of coal-fired electrical generation, and ways to reduce the carbon dioxide emissions from it, what do you believe are the costs and benefits of the choice between efficiency improvements versus seeking to retrofit these plants with carbon dioxide capture technologies? Efficiency improvements and CCS retrofits are compatible approaches, not alternatives. Investments in efficiency improvement today help reduce (albeit modestly) the cost of future retrofit of CO2 capture systems. Technologies for efficiency improvement are available today and can be applied in the near-term. Some are relatively low cost and easy to implement, providing modest improvements, whereas additional options providing greater improvement entail more significant equipment modifications at greater cost. Such upgrades typically provide economic benefits unless they are burdened with costly pollution control add-ons as a result of New Source Review (NSR) requirements. The resulting reduction in CO2 emissions is significant but limited—approximately a 2% reduction in CO2 emissions for every 1 percentage point improvement in plant efficiency. A policy approach that enabled plant modifications for efficiency improvement without incurring the costs of NSR emission control additions/upgrades could encourage investments yielding CO2 reductions of 5–10%. Because CO2 capture equipment is sized on the basis of the volume of flue gas to be treated, efficiency improvements reduce its cost by reducing the volume of flue gas produced per MWh generated. Overall, however, CCS retrofits will remain major capital projects requiring substantial investments and equipment additions— indeed, some plants may not even have room for it. Where feasible, CCS retrofits have the potential for major CO2 emission reductions, in theory up to about 90%. Plant output and/or efficiency are reduced in the process, and retrofits will not generally offer the same possibilities as new plants for optimized ―heat integration‖ to reduce these impacts. Because it will take time to build commercial-scale CO2 capture systems for demonstration, inject significant volumes of CO2 and monitor/verify its subsurface behavior to assure safe and effective storage, it will take considerably longer to apply CCS than to apply efficiency upgrade measures. Accordingly, efficiency improvements can have an impact on electricity sector emissions sooner than can CCS. Question 11a. Do you believe a resistance on the part of state utility commissions and other regulatory bodies to allowing cost recovery for more expensive clean coal technologies has impeded technological progress?

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Answer. We believe the charter of public utility commissions in a number of states requires consideration of the least-cost strategy that satisfies new generating capacity needs in the interest of the ratepayers. This may limit allowance of higher-cost strategies that serve other objectives, such as control of currently unregulated CO2 emissions. Question 11b. Is this an issue that the Institute has looked into in any detail? Answer. No, EPRI has not examined this potential obstacle in particular.

Responses of Jim Rosborough to Questions from Senator Bingaman

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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 multifaceted approach. We can briefly describe our evolving position on this subject as follows: Choice of feedstock is an important component of the solution, and biomass utilization provides GHG reduction benefits at two points: (1) during feedstock conversion, where ―plant emissions‖ occur, and (2) during downstream use of product. (1) During feedstock conversion, CO2 is generated as a natural by-product of hydrocarbon processing. We pursue an efficiency campaign to minimize the CO2 generated in our processes (―maximizing carbon efficiency‖). For the remaining CO2 produced, the percentage of biomass as feedstock directly ofsets or ―neutralizes‖ a corresponding percentage of CO2. This is consistent with the view that CO2 generated from renewable feedstocks is GHG neutral. (2) The percentage of biomass in the feed will also translate into a corresponding percentage of ―renewable carbon‖ in the product. If the last fate of such product were to be combustion, the percentage of renewable carbon in the product would generate a corresponding percentage of ―GHG neutral‖ CO2. A specific example is required to calculate exactly what the expected benefits would be, but the above logic indicates you get a ―double benefit‖ from biomass utilization on a life cycle basis. We believe that maximizing carbon efficiency (minimizing CO2) requires industry to integrate processes, continue to improve in operational disciplines and practices, and make advances in the practical utilization of alternative feedstocks such as biomass. Question 2. You mentioned biomass as a potential feedstock along with coal. We‘ve heard of gasifiers operating with some percentage of municipal solid waste and other materials; are these likely to be suitable for your process as well? We believe so. Gasification enables virtually any hydrocarbon containing material to be utilized as a feedstock. The list includes municipal solid waste (MSW), post-consumer plastic waste, industrial wastes, municipal sewage sludge, as well as various kinds of biomass. We are evaluating a whole slate of technologies that can contribute to the utilization of these

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materials, and feel confident that with our engineering capabilities, we can make this work technically. The primary hurdles are centered on logistics and economics. The question we ask is, ―What do the economics of these technologies look like, and are they practical for improving our competitiveness in a global context?‖ To answer this question, we believe that partnership with government to assist in the acceleration of development and mitigation of initial risk is imperative to making the concept into a reality. Question 3. You generally seem to assume co-production of liquid fuels at an industrial gasification plant. Is this a necessity either because of physical design or economically? Assuming integration of heat recovery and cogeneration of power in each case, can you compare economics of a plant producing chemicals and plastics only to a plant that would produce a mix of products and liquid fuels? Answer. Maximizing carbon eficiency is our goal. The more one integrates complementary industrial processes, the better. Fuels are not necessarily a critical part of the process, depending on the plan, consumer needs, market realities, etc. Our industry benefits from fuels production because those processes also produce chemical feedstocks as a byproduct. 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

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In many ways, the chemical industry is more familiar with CO2 capture than the electric utilities. Question 4a. What opportunities do you believe exist for the two industries to collaborate in a carbon-constrained world? Answer. Dow has engaged in the polygeneration of chemicals, plastics, and electricity for the better part of our 110 years as a company. There is considerable opportunity for collaboration with electric utilities, and in fact we have a history of such activity. A key point we observe as we look forward to solve GHG emissions challenges is this: if you make only electricity, 100 percent of the carbon is converted to CO2. If you make chemicals together with electricity, less than half of the carbon is converted to CO2. Question 4b. Do you believe it is appropriate, or you might say ‗‗fair‘, to require or ask the utility industry, which has significantly less experience with these technologies and processes, to abide by the same timeline that your industry is likely to be capable of? Gasification is essentially a chemical process, and we are expert in operating chemical processes for maximum efficiency and effectiveness. We don‘t see ourselves as having expertise in commercial power generation and distribution, but we believe we can be helpful in bringing our process knowledge into these projects, in a way that shouldn‘t disrupt the timeline. Collaboration with electric utilities is not unlike the joint venture model that we commonly practice, with each participant bringing diferent skills to the party. One of the

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important issues to recognize is that the world‘s power plants aren ‘t yet capture ready. The world needs a solution for legacy plants, and chemistry can be a part of that solution.

Responses of Jim Rosborough to Questions from Senator Corker

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Question 5a. As the Senate prepares to debate cap-and-trade legislation this fall, please give me your perspective on how we should contemplate and deal with coal in the short-term during that debate, apart from the incentives that you laid out in your testimony. Answer. As the most abundant and lowest cost energy and chemical feedstock in the United States, we believe that coal must have a place in our alternative feedstocks portfolio moving forward. Dow is committed to working with industry to determine and implement the cleanest, most effective and eficient technologies for utilizing coal, both in the short term and the long term. We also point out that the United States must avoid a renewed ―rush‖ to natural gas. We are already observing the highest natural gas prices and volatility in history. Further exacerbating the already tight supply/demand balance of natural gas in the US would be detrimental to the economy and further strain the already threatened competitiveness of US industry. We believe that a ―phase in‖ approach for standards is the best way to enable affordable progress. Progress should then trigger stricter standards, and the process can be repeated. Multiple problems require our attention, not the least of which are the need for retrofit solutions for carbon capture at conventional natural gas and coal-fired power plants. The carbon constraints on our energy mix must acknowledge this development curve as we move forward, for any and all feedstock choices. Question 5b. Keeping in mind the need to rely on coal as part of our future energy mix, what do you think are appropriate emissions targets in what amount of time, such that we challenge industry without being unrealistic based on what is technologically possible? Answer. We‘re still evaluating details. We know that successive generations will demonstrate improvements, i.e., the third plant will perform better than the second, which will perform better than the first. We believe that a CO2 emissions standard at 75% of a conventional oil refinery‘s life cycle footprint is feasible. We might need to establish a lower hurdle at first, and apply a graduated standard with a look- back provision so the learnings from the most efficient plants are applied to the early movers. What is critical to consider now is, how will the government and industry partner together to accelerate the necessary experience we need to determine the best approach.

Responses of Don Langley to Questions from Senator Bingaman Question 1. Developers of new power plants tell us they cannot commit to deploying a new technology without a commercial performance guarantee from the vendor. You mention that your company is involved in developing a 300 megawatt oxy-coal combustion plant with

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CO2 capture. Does that mean you are able to issue a guarantee on this technology at that size, or is the developer willing to go without the guarantee? Answer. This situation could best be characterized as ―semi-commercial.‖ The SaskPower project is a leading edge endeavor to achieve positive climate change while using local natural resources in a socially responsible manner. The OxyCoalCombustion (OCC) process utilizes industry-proven enhanced technologies based on years of successful implementation into the commercial market. As such, major items such as the steam generator, turbine and air separation unit can all be offered with commercial guarantees and warrantees. Integrating of these technologies into the OCC process and delivering CO2 to a permanent storage site have first-of-a-kind (FOAK) risks associated with the process, and they are being borne mostly by the owner. Additionally, the presence of FOAK risk naturally leads to contingent designs (multiple solutions or pre-planned modifications to be implemented based upon first experiences) that also add costs to a project. These are also being borne by the owner. In the US, these two added risks are areas where the Federal government could step in and provide financial support that would lead to faster development and deployment, and put the US into a world-wide lead in carbon management. Question 2. It seems a bit like a commercial performance guarantee requires demonstration of the technology at scale but no commercial developer is willing to risk implementing the technology at scale without a performance guarantee. This sounds a bit like a catch-22. Is there an effective way past this problem? Are you aware of how other countries are addressing this issue? Answer. There will never be a substitute for the learning-by-doing final phase of technology development. The electric utility industry is the most capital intensive industry in the US and, therefore, at-scale demonstrations are a required precursor for both the technology provider and the technology adopter. Enabling large demonstration projects (in this case, projects that capture between 500,000 and 1,000,000 tons per year of CO2) is the first step in breaking through the implied conundrum. Following a demonstration, the technology then is validated at commercial scale by an early adopter who has some incentive or special risk mitigation structure to take this scaleup risk. With validation of the technology, performance assurances would become available enabling market forces to sort out the winners in a true commercial context. Cost reductions and capital efficiency come after the initial deployment and with continued use of the technology and processes. Like the DOE, many other governments (EU, Japan and Australia) provide funding for fundamental research and pilot testing of new technologies. The final phase of first commercial use stills tends to fall to the first owner (Utility) to take the risk. Many of those Utilities may still receive government support that is unseen (Japan), or simply be large multinational 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.

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Responses of Don Langley to Questions from Senator Domenici

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Question 3a. Your testimony clearly predicts that commercial-scale carbon capture and storage will not be viable until the year 2020. What do you believe we should be doing in the interim, in addition to research and development, to reduce carbon dioxide emissions from coal-fired electricity? Answer. The Coal Utilization Research Council (CURC) has put together a near-term program to address CO2 emissions from coal-fired plants. First, improving the efficiency of the existing fleet would have an immediate payback in reduced emissions. There are many plants that could make improvements and upgrades that would lead to less coal consumed for the power output. One such upgrade could be the new coal drying technology developed recently with them support of the DOE in North Dakota. Secondly, enact an investment credit or production credit for those who add up to 10% biomass co-firing to their existing plants. With biomass considered a carbon neutral fuel, there would be an immediate reduction of CO2 emissions. The addition of this amount of biomass requires a separate fuel handling and delivery system, which is a capital investment. Finally, ultrasupercritical (USC) power plants are ready to deploy today, and they can be designed with future carbon capture in mind. These plants would reduce CO2 emissions 15–17% below the current fleet-wide average, and coupled with normal retirements of older, less efficient plants, can have an immediate impact in the near term. Question 3b. Do you predict availability of ultra-supercritical plant designs in the year 2020 also, or is commercial application of this technology more imminent? Answer. New ultrasupercritical power plants are available today, as seen in the state-ofthe-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 fleetwide 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

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realize the benefits of the higher efficiency operation and continued reduction in all emissions. Existing plants should evaluate the benefits of efficiency improvements and cofiring 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 road- map 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.

End Notes *

Document has been retained in committee files. Figures 1-12 have been retained in committee files. *** Figure 1 has been retained in committee files. **** Charts 1-2 have been retained in committee files. ***** Figures 2-4 have been retained in committee files. 1 IEA Greenhouse Gas R&D Programme (IEA GHG), ―Estimating Future Trends in the Cost of CO2 Capture Technologies,‖ 2006/5, January 2006. 2 http://www.co2captureandstorage.info/projectlspecific.php?projectlid=26 3 http://www.adv-res.com/pdf/GamelChangerlDocument.pdf 4 http://web 5 http://www.iogcc.state.ok.us/PDFS/CarbonCaptureandStorageReportandSummary.pdf 6 http://www.epa/gov/safewater/uic/pdfs/guideluiclcarbonsequestrationlfinal-03-07.pdf 7 Electric Power Research Institute, ―Electricity Technology in a Carbon-Constrained Future,‖ February 2007, p. 11. 8 ―The Future of Coal: Options for a Carbon-Constrained World,‖ MIT Interdisciplinary Study, March 2007, Executive Summary, p. x. 9 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‖. 10 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.

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**

In: Clean Coal Editor: Klaes G. Douwe

ISBN: 978-1-60741-358-5 © 2010 Nova Science Publishers, Inc.

Chapter 3

CLEAN COAL TECH - POWER PLANT OPTIMIZATION Klaes G. Douwe

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EXECUTIVE SUMMARY The Clean Coal Technology Demonstration Program (CCTDP) and the two following programs—the Power Plant Improvement Initiative (PPII) and the Clean Coal Power Initiative (CCPI)—are government and industry co-funded programs. The goal of these programs is to demonstrate a new generation of innovative coal-utilization technologies in a series of projects carried out across the country. These demonstrations are conducted on a commercial scale to prove the technical feasibility of the technologies and to provide technical and financial information for future applications. A further goal of these programs is to furnish the marketplace with a number of advanced, more efficient coal-based technologies that meet increasingly strict environmental standards. These technologies will help mitigate the economic and environmental barriers that limit the full utilization of coal. To achieve these goals, beginning in 1985 a multi-phased effort has been administered by the U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL). The CCTDP, the earliest program, initiated five separate solicitations. The next program, the PPII, sent out one solicitation, and the CCPI has had two solicitations to date. The projects selected through these solicitations have demonstrated technology options with the potential to meet the needs of the energy markets while satisfying relevant environmental requirements. This report describes four projects aimed at improving or optimizing the performance of coal-fired power plants. All four projects are being conducted under the CCPI and PPII programs. The first project deals with upgrading high moisture lignite by partial drying to enhance its quality and improve overall plant performance. The remaining three projects involve the development of software that optimizes overall power plant performance or some aspect of performance by incorporating features of artificial intelligence (AI), a decisionmaking capability that simulates the human brain.

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Great River Energy‘s Coal Creek Station

The Lignite Fuel Enhancement project is demonstrating improved plant performance by using waste heat to partially dry lignite, which is normally high in moisture. The Neural Network-Intelligent Soot-blowing (NN-ISB) project with the Tampa Electric Company (TECO) Big Bend Power Station was intended to demonstrate improved efficiency and lower emissions of nitrogen oxides (NOX) by using a computer-based neural network to determine when sootblowing is needed. The Mercury Specie and Multi-Pollutant Control project with Pegasus Technologies is demonstrating the capability to optimize mercury speciation and control of emissions from an existing power plant using state-of-the art sensors and neural network-based optimization software at NRG Texas‘s Limestone Station. The Demonstration of Integrated Optimization Software project at Dynegy Midwest Generation‘s Baldwin Energy Complex, where NeuCo, Inc., is demonstrating the integration of five separate optimization computer programs to optimize overall power plant operation.

BACKGROUND: POWER PLANT OPTIMIZATION Overall optimization of a coal-fired power plant is a highly complex process. One must first decide what constitutes optimal performance. Obvious answers include maximum thermal efficiency, lowest possible emissions, lowest possible cost, readily marketable byproducts, and maximum system availability for power generation. In reality, these goals—and others—are interrelated. In some cases, however, these optimization goals are at odds with each other. For example, high excess air will result in better carbon burnout and less carbon monoxide but will also result in higher emissions of nitrogen oxides (NOX). These interactions must be kept in mind and addressed with any optimization program. There are a number of relatively fixed items that affect overall plant operation. These include boiler design, cooling water conditions, burner type, design steam conditions, and environmental control systems that capture and remove particulate matter, sulfur dioxide (SO2), NOX, and mercury. Coal quality is also a major factor that affects plant performance. High moisture and/or ash content decreases efficiency and increases wear and power

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requirements on the pulverizers. High sulfur content results in more reagent consumption and increased by-product generation. The benefits of optimizing the overall process of generating power from coal are significant. Efficiency is increased, total maintenance costs are reduced, emissions are decreased, and reliability is improved. While the greatest benefit can be achieved by optimizing the overall operation, important benefits can also be achieved by optimizing one or more of the factors that contribute to the overall efficiency of the plant. Many optimizations can yield substantial positive results. For instance, use of lignite and sub-bituminous coals, which are high in moisture, lowers the boiler efficiency, increases the load on the pulverizers, and increases flue gas volume. Drying the coal before it is fed to the preparation system is generally not practical due to the energy required. Switching to a higher quality coal, even if available, is often not practical either due to cost or to the fact that a boiler designed for a specific coal may not function as well with other coals. If such a switch is made, the unit may need to be de-rated. So, if drying the coal can be economically integrated into the overall power plant process, potential benefits are substantial. There are several obvious systems that can be optimized independently and result in better performance. Some involve simply upgrading a specific piece of equipment. For example, a refurbished steam turbine will improve heat rate and result in less fuel consumption per megawatt (MW). The cost of electricity is then reduced, as are the emission rates of some pollutants. In some cases, optimizing one aspect of boiler operation can have several benefits. For example, during boiler operation, ash slowly builds up on boiler tubes. This causes reduced heat transfer to the boiler feed water and steam which results in lower efficiency and higher NOX emissions. The buildup is removed by blowing it off the tubes with high-pressure steam. But when sootblowing occurs, the electrostatic precipitator (ESP), or baghouse, is temporarily overwhelmed by the high particulate load at the inlet. Sootblowing is traditionally done on a set schedule rather than as needed. This results in some boiler sections accumulating excessive ash on the tubes while others, having little ash buildup, are serviced when it is not required. Optimized sootblowing can solve these problems by using sensors and artificial intelligence (AI) software to determine when a particular section of the boiler needs to have the ash removed from the tubes, thus minimizing steam consumption (and improving heat rate), reducing the frequency of a high particulate load in the flue gas, and reducing NOX formation. As one would expect, optimizing the operation of multiple components normally gives better results than optimizing one aspect of the operation. Maximizing the overall performance of multiple pieces of equipment does not normally have an adverse effect on the other power plant components. However, when using AI/neural network systems to optimize multiple aspects of power plant operation, care must be taken to consider the possible negative impact on other parameters. This can best be accomplished by designing the software packages to communicate with each other through a management software package. This document describes four optimization projects within the PPII and CCPI programs. The following are brief descriptions of the four projects: In the Lignite Fuel Enhancement project, Great River Energy has installed a full-scale prototype dryer module to supply one-sixth of the coal required for a 546 MW unit. Results to date have shown improved performance in overall operation of this unit. In the next phase of this project, Great River Energy will design, construct, and perform full-scale, long-term

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operational testing on a complete set of dryer modules to supply all the coal needed for the full operation of this unit. The Neural Network-Intelligent Sootblower (NN-ISB) project with the Tampa Electric Company (TECO) Big Bend Power Station is complete. This project showed that the concept of using a neural network system to optimize the sootblowing process is sound but that additional development and better equipment are needed. Mechanical problems with sensors and water cannons were encountered and overall results were affected by these issues. However, some benefit was obtained with respect to stack opacity and nitrogen oxides reduction. In the Mercury Specie and Multi-Pollutant Control project, Pegasus Technologies will utilize state-of-the-art sensors and neural-network-based optimization and control technologies to maximize the proportion of mercury species that are easy to remove from the boiler flue. This project will demonstrate how integrating sensors, controls, and advanced analysis techniques into multiple facets of plant operation can lead to improved economics and environmental compliance. With the Demonstration of Integrated Optimization Software project at Dynegy Midwest Generation‘s Baldwin Energy Complex, NeuCo, Inc., is integrating and optimizing their software, SCR-Opt™, CombustionOpt®, SootOpt™, PerformanceOpt®, and MaintenanceOpt™. ProcessLink® is the integration software that coordinates these programs to achieve overall plant goals. The project is ongoing as of this time and results to date appear promising.

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ARTIFICIAL INTELLIGENCE Artificial intelligence (AI) is commonly defined as the science and engineering of making intelligent machines, especially intelligent computer programs. Relative to applications with coal-fired power plants, AI consists of aspects or considerations that deal with the following: Neural networks, which mimic the capacity of the human brain to handle complex nonlinear relationships and ―learn‖ new relationships in the plant environment Advanced algorithms or expert systems that follow a set of pre-established rules written in codes or computer language Fuzzy logic, which involves evaluation of process variables in accordance with approximate relationships that have been determined to be sufficiently accurate to meet the needs of plant control systems Neural networks (NNs) are a class of algorithms that simulate the operation of biological neurons. The NN learns the relationships between operating conditions, emissions, and performance parameters by processing the test data. In the training process, the NN develops a complex nonlinear function that maps the system inputs to the corresponding outputs. This function is passed on to a mathematical minimization algorithm that finds optimum operating conditions. NNs are composed of a large number of highly interconnected processing elements that work in parallel to solve a specific problem. These networks, with their extensive

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ability to derive meaning from complicated or imprecise data, can be used to extract patterns and detect trends that are too complex to be detected by either humans or other computer techniques. NNs are trainable systems that can ―learn‖ to solve complex problems and generalize the acquired knowledge to solve unforeseen problems. A trained NN can be thought of as an expert in the category of information it has been given to analyze. NNs are considered by some to be best suited as advisors, i.e., advanced systems that make recommendations based on various types of data input. These recommendations, which will change as power plant operations change, suggest ways in which plant equipment or technologies can be optimized. Advanced algorithms, on the other hand, are programmed to incorporate established relationships between input and output information based on detailed knowledge of a specific process. They are used by computers to process complex information or data using a step-by-step, problem-solving procedure. In particular, genetic algorithms provide a search technique to find true or approximate solutions to optimization problems. These algorithms must be rigorously defined for any computational process since an established procedure is required for solving a problem in a finite number of steps. Algorithms must tell the computer what specific steps to perform and in what specific order so that a specified task can be accomplished. Advanced algorithms are now part of the sophisticated computational techniques being successfully applied to power plants to increase plant efficiency and reduce unwanted emissions. Fuzzy logic (FL), the least specific type of AI software, is equipped with a set of approximate rules used whenever ―close enough is good enough.‖ Fuzzy logic is a problem-solving control-system methodology that has been used successfully with large, networked, multi-channel computers or workstation-based data-acquisition and control systems. FL can be implemented via hardware, software, or a combination of both. Elevators and camera auto-focusing systems are primary examples of fuzzy logic systems. Fuzzy logic stops an elevator at a floor when it is within a certain range, not at a specific point. FL has proven to be an excellent choice for many control system applications since it mimics human control logic. By using an imprecise but very descriptive language, FL deals with input data much like a human operator. FL is very robust and provides a simple way to arrive at a definite conclusion based upon vague, ambiguous, imprecise, or missing input information. However, while the FL approach to solving control problems mimics human decision-making, FL is much faster. The FL model is empirically based, relying on operator experience rather than technical understanding of the system.

LIGNITE FUEL ENHANCEMENT PROJECT Introduction The use of low-rank coals (lignite and subbituminous) has seen a significant increase in recent years. Because of the low sulfur content of such coals, many units have adopted fuel switching to meet sulfur emissions specifications, and other units have been built specifically to burn low-rank coals. However, a major disadvantage of low-rank coals is their high

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moisture content, typically 25 to 40 percent. When such coal is burned, considerable energy is required to vaporize the moisture it contains, thus raising the heat rate of the power plant and lowering its efficiency. Fuel moisture has many effects on unit operation, performance, and emissions. As fuel moisture decreases, the fuel‘s heating value increases so that less coal needs to be fired to produce the same electric power, thus reducing the burden on the coal-handling system. Drier coal is easier to convey as well, which reduces maintenance costs and increases availability of the coal to the handling system. When the crushed coal is gravity-fed into bunkers, the drier coal flows more readily than the wet coal, causing fewer feed hopper bridging and plugging problems. Drier coal is easier to pulverize as well so that less mill power is needed to achieve the same coal fineness. Finally, with less moisture in the fuel more complete drying of coal can be achieved in the mill, which results in an increased mill exit temperature, better conveying of coal in the coal pipes, and fewer coal pipe plugging problems. The mixture of pulverized coal and air from the pulverizers is combusted in the burners. With drier coal, the flame temperature is higher since there is less moisture to evaporate. At the same time, heat transfer processes in the furnace are modified. The higher flame temperature results in a larger radiation heat flux to the furnace walls. Also, drier coal results in less moisture in the flue gas, which changes the radiation properties of the flame. The change in the flame emissivity also affects the radiation flux to the wall. With a higher flame temperature, the temperature of coal ash particles is correspondingly higher, which could increase furnace fouling and slagging, reducing heat transfer and resulting in a higher flue gas temperature at the furnace exit. However, the reduction in coal flow rate as fuel moisture is reduced also reduces the amount of ash entering the boiler, which leads to less solid-particle erosion in the boiler and decreased boiler maintenance cost.

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THE CLEAN COAL TECHNOLOGY PROGRAM The DOE commitment to clean coal technology development has progressed through three phases. The first phase was the Clean Coal Technology Demonstration Program (CCTDP), a model of government and industry cooperation that advanced the DOE mission to foster a secure and reliable energy system. With 33 projects completed, the CCTDP has yielded technologies that provide a foundation for meeting future energy demands that utilize the vast U.S. reserves of coal in an environmentally sound manner. Begun in 19 5, the CCTDP represents a total investment value of over $ .25 billion. The DOE share of the total cost is about $1. 0 billion, or approximately 0 percent. The project industrial participants (non-DOE) have provided the remainder, nearly $2 billion. Two programs have followed that have built on the successes of the CCTDP. The first is the Power Plant Improvement Initiative (PPII), a cost-shared program patterned after the CCTDP and directed toward improved reliability and environmental performance of the nation‘s coal-burning power plants. Authorized by the U.S. Congress in 2001, the PPII involves five projects that focus on technologies enabling coal-fired power plants to meet increasingly stringent environmental regulations at the lowest possible cost. Four projects have been completed and one is still active. The total value of these projects is $71.5 million, with DOE contributing $ 1.5 million or 44.6 percent.

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The second program is the Clean Coal Power Initiative (CCPI), also patterned after the CCTDP. Authorized in 2002, the CCPI is a 10-year program having a goal of accelerating commercial deployment of advanced technologies to ensure that the nation has clean, reliable, and affordable electricity. Total Federal funding will be up to $2 billion, with a matching cost share by industrial participants of at least 50 percent. To date, two solicitations have been completed and nine projects have been awarded or are in negotiation. These projects have a total value of approximately $2.68 billion. The DOE share is $5 million or 19.9 percent.

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The flue-gas flow rate from a furnace firing dry coal is lower than one firing wet fuel, and the specific heat of the flue gas is lower due to its lower moisture content. A lower flue gas flow rate also results in a lower rate of convective heat transfer. Therefore, despite an increase in initial flue gas temperature with drier fuel, less heat will be transferred to the water or steam in the boiler convective pass. Drier coal is expected to lower the temperature of flue gas leaving the economizer and air preheater (APH). APH performance will also be affected by changes in the ratio of air and flue gas flows through the APH and changes in specific heat. Improved overall process efficiency will result from drier coal as the auxiliary power decreases due to decrease in forced draft, induced draft, and primary air fan power as well as decrease in mill power. Previously, a number of proposals have been advanced to dry low-rank coals prior to combustion, but none of these efforts has resulted in a successful commercial operation. The two major problems with drying schemes before this have been the cost of the energy required and the fact that low-rank coals become pyrophoric when dried beyond a certain point. The Great River Energy Lignite Fuel Enhancement Project overcomes these problems by using waste heat to dry the coal and removing only about 25 percent of the moisture, enough to appreciably improve plant performance but not enough to cause handling problems.

Project Objectives The objective of this project is to demonstrate an economic process of moisture reduction of lignite, thereby increasing its value as a fuel in power plants. The project is being conducted at the Great River Energy‘s Coal Creek Station in Underwood, North Dakota. The demonstration activities focus on using low grade condenser waste heat and flue gas in the plant to lower the moisture content of the coal by about 10 percentage points (e.g., reduce the lignite moisture from 40 to 30 percent). A phased implementation is planned: In the first phase, a full-scale prototype dryer module was designed for operation of one of the pulverizers on one of the two 546 MW units at the Coal Creek Station. The objectives of prototype testing were to gain operating experience, confirm pilot results, and determine the effect of air flow rate, bed coils, bed depth, and coal feed rate on dryer operation in order to optimize performance. The lessons learned from the prototype were incorporated into the design of the dryers being installed in the second phase. A total of four dryers will be built for Unit 2. Although operating with wet lignite requires seven pulverizers, six will provide all the dried lignite required by the boiler.

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Aerial view of Great River Energy‘s Coal Creek Station lignite power plant

Schematic of Lignite Coal Drying Using Waste Heat From Condenser Water and Flue Gas

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Following successful demonstration in the first phase, Great River Energy is designing and constructing a full-scale, long-term operational test on a complete set of dryer modules needed for full power operation of one 546 MW unit (four dryers). The coal will be dried to a number of different moisture levels. The effect of coal drying on plant performance will be measured with respect to increase in plant efficiency and availability, reduction in emissions, and improvements in plant economics. The dryer design and operating conditions will be determined for optimal plant performance.

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Project Description In response to the first round of the Clean Coal Power Initiative, Great River Energy (GRE) submitted a proposal for a full-scale test of a lignite-drying technology that they had been developing since the 1990s. The previous work included bench-scale research and development, field trials, and preliminary drying studies. These studies convinced GRE of the technical feasibility and economic benefits of lignite drying and prompted the submittal of their proposal. The Department of Energy evaluated and selected their proposal, and a cooperative agreement was awarded on July 9, 2004. The project team for the Lignite Fuel Enhancement Project consists of GRE, participant and site provider; the Electric Power Research Institute, collaborator; Lehigh University, collaborator; Barr Engineering, lignite handling; and Falkirk Mining and Couteau Properties, lignite supplier. The project is sited at GRE‘s Coal Creek Station in Underwood, North Dakota. Coal Creek Station is a mine-mouth plant, burning approximately seven million tons of lignite per year and consisting of two 546 MW, tangentially fired Combustion Engineering boilers. Steam is produced at 2,400 psig and 1,000 oF with a 1,000 oF reheat temperature. The Coal Creek station has eight pulverizers per unit (seven active and one spare). The station has two single reheat General Electric G-2 turbines. The figure at left provides a simplified flow diagram of the lignite drying process. Warm cooling water from the turbine exhaust condenser goes to an air heater where ambient air is heated before being sent to the fluidized bed-coal dryer. The cooling water leaving the air heater is returned to the cooling tower. A separate water stream is passed through coils in the fluidized bed-coal dryer (a two-stage dryer is used to enhance heat transfer). The purpose of these coils is to provide additional heat to the fluidized bed to reduce the amount of air required. The dried coal leaving the fluidized bed is sent to a pulverizer and then to the boiler. Air leaving the fluidized bed is filtered before being vented to the atmosphere. The technical aspects of the project are being implemented in two phases. The first phase involved the construction and operation of a prototype dryer, a full-sized dryer with a maximum capacity of 112.5 tons/hour (225,000 lb/hour). It was designed to reduce the moisture content of lignite from 38 percent to 29.5 percent and improve the higher heating value from 6,200 Btu/lb to 7,045 Btu/lb. The prototype unit was fully automated and integrated into the plant control system. The first coal was introduced into the prototype dryer on January 30, 2006, and performance testing was carried out in March and April 2006.

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Benefits Firing drier coal results in improved boiler efficiency and unit heat rate, primarily due to lower stack loss and lower auxiliary power (lower fan, pulverizer, cooling tower, and coal handling power). This performance improvement will allow greater electrical output with existing equipment. Performance of back-end environmental control systems (scrubbers and electrostatic precipitators) will also improve with drier coal due to the lower flue gas flow rate and longer residence time. The reduction in required coal-flow rate and modified temperature profile will directly translate into lower emissions of NOX, carbon dioxide (CO2), SO2, and particulates. For units equipped with wet scrubbers, mercury emissions resulting from firing drier coal would also be reduced. This is due to reduced APH gas outlet temperature, which favors the formation of mercuric oxide and mercuric chloride at the expense of elemental mercury. These oxidized forms of mercury are water-soluble and can therefore be removed in a scrubber. During testing of the prototype coal dryer in 2006, at a feed rate of 75 tons/hour (14 percent of total fuel rate to the 546 MW unit), there were no major operating problems. The moisture of the total coal was reduced by only about 1.1 percentage points. Yet there were significant benefits in the prototype dryer operation for the 546 MW unit. Performance measures showed that the lignite flow rate was reduced by 2 percent, pulverizer power was reduced by 3.3 percent, boiler efficiency improved 0.5 percent (absolute), net unit heat rate improved 0.5 percent, NOX emissions decreased 7.5 percent, and SO2 emissions decreased 1.9 percent. These results indicate that there will be significant improvements in operations once the project is fully implemented. The potential market for GRE‘s coal-drying technology is quite sizeable. There are 29 units with a total capacity of 15.3 gigawatts (GW) that are burning lignite directly, and another 250 units with a total capacity of over 100 GW burning Powder River Basin coal. If all these units were to adopt coal drying, the economic and environmental benefits would be quite large.

NEURAL NETWORK INTELLIGENT-SOOTBLOWER OPTIMIZATION PROJECT Introduction A neural-network-driven computer system offers the potential to optimize sootblowing in coal plant boilers, reduce NOX emissions, improve heat rate and unit efficiency, and reduce particulate matter emissions. Installed at the Tampa Electric Company (TECO) Big Bend Power Station in Hillsborough County, Florida, the Pegasus Technologies neural networkintelligent sootblowing (NN-ISB) system was designed to be used in conjunction with advanced instrumentation and water cannons to prevent soot from building up in a boiler. Of the four coal-fired units at the power station, Unit No. 2 was selected for installation of the NN-ISB control system. Fired with bituminous coal, this wet bottom pressurized Riley Stoker single-drum radiant boiler has a total of 48 coal nozzles on a single elevation, 24 on each side, firing toward the center line of the furnace. The final project cost for the NN-ISB control

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system (equipment/instrumentation, software, testing, and reporting included) was $3.4 million, including a 27 percent Department of Energy (DOE) cost share. Software costs of a few hundred thousand dollars were a small part of the total cost. Project testing of the NNISB was completed in December 2004, and the final report on the system was issued in September 2005.

Tampa Electric Big Bend Power Station

Project Objectives The project objective at the Big Bend plant was to develop a neural-network-driven system that could initiate, control, and optimize sootblowing in response to real-time events or conditions within the coal-plant boiler rather than relying on general rule-based protocols. The project demonstrated and assessed a range of technical and economic issues associated with the sensing, management, display, and human interface of sootblowing goals as they relate to emissions and efficiency of a coal-fired utility boiler. Specifically, this optimization process targeted reducing baseline NOX emissions by up to 30 percent, increasing unit efficiency by 2 percent, and reducing particulate matter (stack opacity) by 5 percent.

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Communications Architecture at Big Bend Power Station

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Project Description This neural network project was implemented under the Power Plant Improvement Initiative (PPII), a DOE program designed to demonstrate plant improvement technologies and processes in commercial settings. At the time of the award, this installation was the first domestic project to use neural network technology to optimize the sootblowing process within a boiler. Started in 2001 after a series of brownouts and blackouts had plagued major regions of the country, the initiative targeted new technologies that could help coal plants boost their output and improve their environmental performance. The Big Bend project was designed to be a full-scale demonstration of the neural-network-driven technology on a large commercial boiler, using state-of-the-art controls and instruments to optimize boiler operation and systematically control boiler slagging and fouling. In a coal-fired boiler, the continuing buildup of ash and soot on the boiler tubes leads to reduced boiler efficiency. If periodic ash and soot removal (sootblowing) is not performed, this leads in turn to higher flue gas temperatures and ultimately to higher NOX formation and reduced efficiency. Therefore, cleaning the heat-absorbing surfaces is one of the most important boiler auxiliary operations. Typically, sootblowing uses mechanical devices for online cleaning of fireside boiler ash and slag deposits on a periodic basis. Sootblowers clean by directing steam or water through nozzles against the accumulated soot and ash on the heattransfer surfaces in order to remove the deposits and maintain heat-transfer efficiency. Basically, sootblowers consist of four components: a tube or lance that is inserted into the

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boiler and carries the cleaning medium, nozzles in the tip of the lance to accelerate and direct the cleaning medium, a mechanical system to insert or rotate the lance, and a control system. Because it either uses steam that would otherwise be used to generate electric power or it requires energy for pumps or compressors, sootblowing has a direct impact on plant efficiency. Thus, optimizing sootblower operation is important in maximizing unit efficiency. Typically, sootblowers operate on a specified timed cycle or, alternatively, operation is initiated by an operator who believes sootblowing is needed. The purpose of an ―intelligent‖ sootblowing system is to decide when to sootblow based on information from boiler instruments. The overall objective is to sootblow when, and only when, necessary. The Pegasus Technologies NN-ISB control system uses a neural network to model the characteristics of the boiler. Designed to recognize patterns in input data, this network must be ―trained‖ using historical data before it can associate a particular pattern with a corresponding plant state. Once this training has been completed, the system can respond rapidly to new inputs. An advantage of a neural network is that if any inputs are faulty the prediction capability degrades only gradually compared to most other modeling techniques. The project installed at Big Bend Unit No. 2 includes 16 heat flux sensors, 8 slag sensors, a heat transfer advisor, acoustic pyrometers, a sootblower control system, an online performance monitor (OPM), and an advanced calibration monitor (ACM). For the communications layout, the combustion optimizing system and intelligent sootblowing (ISB) software were loaded into one computer. For this application, the models were partitioned so they could function separately or work interactively. This approach was important since it permits upgrades to existing power plants as well as applications to new boilers. Although the demonstration was carried out on the hardware and software systems developed for this project, the equipment (including the distributed control system) could be obtained from any manufacturer. After verification that the core elements of the NN-ISB system were satisfactorily installed and operational, detailed model tuning was completed. During this task, the unit was operated under a variety of conditions, including some non-ideal variations. This helped to define acceptable operating limits and constraints used by the neural network while optimizing the system. During system optimization, appropriate adjustments were made to allow the system to ―learn‖ and to make recommendations on Unit 2 operation, including both manual or advisory (open-loop) and automatic (closed-loop) operation. The advisory mode provided recommendations to the operators and engineers, who used those results to further tune the system. This activity also proved very valuable in assessing and recording the performance and status of the new sensors and systems.

Results The automated closed-loop activation of the sootblowers during this project confirmed that neural-network, adaptive sootblowing can benefit efficiency. There was a clear improvement at low loads, with the benefit decreasing as the load increased. During closedloop operation of the NN-ISB, Pegasus reported that efficiency gains were in the range of 0.1 to 0.4 percentage points compared to baseline. Results with open-loop operation were slightly

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lower. With more operating experience, gains at the high end of the load range should be achievable.

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Pegasus Technologies NN-ISB Control System

NRG Texas‘s Limestone Power Plant in Jewett, Texas

NN-ISB closed-loop (automatic) operation was shown to be better than open-loop (nonneural network baseline) operation. Other Pegasus results indicated an improvement of 1.0 to 1.5 percent in opacity for closed-loop compared to open-loop operation during certain tests. While it is reasonable to expect that optimizing sootblowing would be beneficial for NOX reduction (due to an improved temperature profile in the furnace), the Big Bend project was unable to clearly demonstrate this. Supporting equipment and material issues (e.g.,

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unavailability of the water cannons during the NN-ISB tests, underperformance of much of the instrumentation) greatly limited the optimization software from performing as expected. Prior to this project, sensors and controls related to sootblowing were usually treated as isolated systems. In contrast, the Big Bend NN-ISB system had the ability to understand, evaluate, and optimize the process as an entire system with multiple, real-time objectives. Integration of the sensors went well and communication was established to the neural network system with all sensors and elements of the project. The project demonstrated that such systems can be linked together despite the use of proprietary networks. Further, it confirmed that the sensors can provide data that can be correlated to achieve a set of objectives. Generally, the NN-ISB system appears to have merit and can improve boiler performance.

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Conclusions The major conclusion from this project is that the Pegasus Technologies NN-ISB control system is a sound idea with significant potential. The Big Bend project successfully demonstrated a neural network, closed-loop operation on a full-scale boiler without causing unit upsets or violating any constraints—and it also achieved operator acceptance. The NNISB appears to provide generating companies with an integrated solution that will assist in optimal economic and environmental real-time, online operation of a unit. The NN-ISB is modular in design and can be readily applied to a variety of power generating units. The solution architecture and infrastructure are designed to allow full or staged deployment, depending on the needs of the generating company. The technology applied throughout allows unit flexibility (i.e., existing systems can be integrated within the overall solution) and is extendible (new modules/new equipment can be readily modeled and incorporated). In general, the project provided a testing ground for several innovative measurement devices and feedback on their operation that may also lead to improved instruments. Since some equipment and instrumentation (e.g., water cannons, heat flux sensors, slag sensors, and acoustic pyrometers) did not fully operate as expected during this testing, an additional project with improved equipment and instrumentation may be needed in order to fully quantify all the benefits. Other project goals were also achieved: Promoted the use of coal by making coal more fuel-efficient automatically, reducing all pollutants on a per megawatt-hour basis. In addition, reducing NOX emissions should lower the resistance to coal use for electrical generation. Enabled rapid deployment into the market. All coal-fired boilers employ sootblowers which, in turn, require control systems. Since current systems cannot achieve the desired results in sootblowing operations, a neural network control system appears to offer significant advantages. Further, no new hardware needs to be developed since the hardware is ―off the shelf‖ and readily available. Expanded U.S. revenues through world-wide market acceptance. The same rapid deployment capability and acceptance by domestic plants should apply to offshore coal-fired boilers. Since the United States is presently the world leader in AI (of

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Klaes G. Douwe which the neural network system is a subset) there should be minimal competition from offshore suppliers.

In summary, the project provided valuable information on neural networks and the positive results should encourage other power plants to install these systems to control sootblowing, improve boiler efficiency, reduce NOX emissions, and improve other aspects of their operations. Although equipment and instrumentation issues may have precluded the NNISB project from achieving all of its goals, the project clearly demonstrated the validity of using AI to control a major aspect of boiler operation.

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NRG‘s Limestone Power Plant

MERCURY SPECIE AND MULTI-POLLUTANT CONTROL PROJECT Introduction Implemented under the CCPI, the project at the NRG Texas (formerly Texas Genco) Limestone Power Plant in Jewett, Texas, is designed to demonstrate the capability to optimize mercury speciation and control emissions from an existing power plant. NRG Texas, with a generating capacity of more than 14,000 MW, has plants primarily based on fossil fuels and is an important producer of electricity in Texas. Performed by Pegasus Technologies, Inc., a division of NeuCo, Inc., this demonstration is occurring on an 890 MW utility boiler that uses 14,500 tons of coal per day. The Pegasus technology provides plant operators with the ability to assess detailed plant operating parameters that affect mercury capture efficiency, overall heat rate, particulate removal, and flue gas desulfurization (FGD) efficiencies. These data are also provided to a neural network optimization system that controls plant subsystems to provide the lowest possible pollutant emissions, highest heat rate, and least risk of environmental non-compliance, all with minimal capital expenditure. Once demonstrated, this technology is anticipated to have broad application to existing coal-fired boilers and a positive impact on the quality of saleable by-products such as fly ash.

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The project began in April 2006, with performance testing targeted for December 2008. This estimated $15.6 million project will be 38 months in duration, with a DOE cost share of 39 percent.

Project Objectives

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On a large utility coal-fired boiler, Pegasus Technologies is demonstrating the ability to affect and optimize mercury speciation and multi-pollutant control using non-intrusive advanced sensor and optimization technologies. Plant-wide advanced control and optimization systems are being integrated into a coal-fired, steam electric power plant in order to minimize emissions while maximizing the efficiency and by-products of the plant. Advanced solutions utilizing state-of-the-art sensors and neural-network-based optimization and control technologies are being used to maximize the portion of the mercury vapor in the boiler flue gas that is oxidized or captured in particle and chemical bonds, resulting in lower uncontrolled releases of mercury. This neural-network-based control and optimization system gathers data from coal composition, combustion gas composition, mercury species, feed rates, etc., and uses this information to optimize power plant operations. The greatest advantage of neural networks in power plants is their ability to generalize from previous information and develop possible similar patterns for future use. Such intelligent control is expected to improve mercury capture by over 40 percent, reduce NOX emissions by 10 percent, reduce fuel consumption by 0.5 to 2.0 percent, and improve operating flexibility.

Control System Schematic for NRG Texas Limestone Power Plant

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Project Description The estimated 48 tons of mercury emitted annually by domestic coal-fired power plants is about one-third of the total amount of mercury released annually from all human activities in the United States. Mercury emissions take a number of chemical forms—or species— including the pure element, as part of a gaseous compound, or bound to particulates in flue gas. Certain mercury species, such as mercury that is adsorbed onto fly-ash particles or bound in the FGD, are relatively easy to remove from flue gas. Adjusting certain parameters during combustion can optimize the speciation process and maximize the mercury captured in particle bonds. This results in greater capture of mercury and lower uncontrolled releases. The NRG Texas demonstration power plant is equipped with a tangentially-fired boiler that uses a blend of 70 percent Texas lignite and 30 percent Powder River Basin subbituminous coal, which are known to emit relatively high levels of elemental mercury under routine combustion conditions. Pegasus Technologies will apply sensors at key locations to evaluate the mercury species (elemental and oxidized mercury), develop optimization software that will result in the best plant conditions to promote mercury oxidation and minimize emissions in general, and use neural networks to determine the optimization conditions. The unit is equipped with a cold-side ESP rated at approximately 99.8 percent particulate removal efficiency and a wet limestone FGD system rated at approximately 90 percent SO 2 removal efficiency. Both devices are capable of high mercury-capture efficiency, especially when the mercury is in an oxidized state rather than an elemental vapor state. Using a neural network to affect and optimize mercury speciation and multi-pollutant control, the non-intrusive advanced sensor and optimization technologies will act as a highly trained operator, making decisions on inputs to the process by measuring and learning the outputs. By using AI and simulation technologies, Pegasus will minimize the use of raw material resources and pollutant emissions while simultaneously optimizing the operating capabilities of the plant. This project involves the installation and demonstration of sensors and optimization software in six separate technology packages. While the modular design is transparent to this project, it is important to the future marketing of this system because of the flexibility needed with utilities to include or exclude a particular module based on either the existing equipment or budget for a specific plant. Many of the sensors and optimizer technologies that will be installed are utilized across the modules; therefore, they have been included under the module in which they are most used. The technology packages for this project include the following: The intelligent fuel management system (FMS): The FMS is composed of the Pegasus Combustion Optimizer system, the Ready Engineering CoalFusion™ system, and a Sabia elemental analyzer. The mercury specie control system: This system includes the boiler area optimization, Pegasus virtual online analyzers, and various sensors. Mercury emissions will be measured through continuous emission monitors. The advanced ESP optimization system: The ESP optimization system is composed of a carbon-in-ash virtual online analyzer, a carbon-in-ash sensor, and Pegasus ESP optimization software.

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The advanced ISB system: The ISB system is made up of Pegasus ISB software. This module has been previously demonstrated. The advanced FGD optimization system: The FGD System is composed of Pegasus FGD optimization software. The intelligent plant (unit optimization): This is the Pegasus i-Plant Optimization System that will contain a simulator and will arbitrate among the solutions for the above systems. This system will interface with users through a commercially available computer.

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Key locations where sensors will be applied to evaluate mercury species

Each technology package includes non-intrusive sensors and the appropriate software needed for data acquisition, optimization, and integration with the overall neural network. In using this approach, all facets of coal-fired power plant operation will be optimized by balancing the inputs and outputs of the plant within a realm of multiple constraints. The intended result is to improve the efficiency of plant operations while operating within regulatory and commercial constraints. During the first of three performance phases, sensor installation, software system design, and baseline operating metric testing will be completed. Instruments or instrument technology packages to be installed include a coal elemental analyzer (part of the fuel management system), mercury sensors, coal flow sensors, laser-based furnace gas speciation sensors, online carbon-in-ash sensor (located in the ESP), communications links for data acquisition and control, and related computers, controllers, and Pegasus optimization products. Baseline testing will be performed to establish comparative data for the operational testing that will follow in Phase 3. After initial baseline testing, parametric testing will be performed to exercise various combinations of control variables to determine their effect on mercury speciation and by-product generation and to determine overall plant performance. These data will be used in Phase 2 to adjust the neural network for optimization control. During Phase 2, software installation, data communications modification, and distributed control system modification will be achieved. The test plan data and historical data (if applicable) will be evaluated to confirm that no irregularities exist prior to model development. After extraneous data (e.g., calibrations) are eliminated from the data set, operating issues and constraints will be reviewed as part of further model development.

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Control models will be developed to characterize the effect of control variables on the operational characteristics of the boiler, mercury speciation, and by-product generation. Models will be created that accurately and robustly represent the effects that changes in the unit have on the outputs to be optimized. Before the control models are implemented in an online system, offline simulation will be performed. The models will then be evaluated and demonstrated to Limestone Power Plant operators and engineers so their input can be used to finalize the behavior of the models. Pegasus uses pre-designed and custom methods for constraining the models under various design and operational limitations. These are dynamic constraints that fluctuate with load, number of burners in service, rate of change, etc. After the initial modeling is completed, a shorter series of tests will be conducted. These will involve setting up operational parameters to verify the predictive capabilities of the neural network model and to assure that the model has been properly trained. During this period, the models will be coarsetuned. Control loops will first be tested one at a time and then as groups to deal with the individual loop characteristics before dealing with the interactive characteristics. At the end of Phase 2, a decision will be made whether to initiate work under Phase 3 or to conclude the project after the successful demonstration of closed-loop operability for neural networks and controllers. Phase 3 plans include demonstration and validation of all systems as well as a comparison of the test results with the project objectives. Extended mercury and multipollutant testing will be conducted. The technology packages—the fuel management system, combustion and mercury control system, ESP system, ISB system, FGD system, and intelligent plant (i-Plant) system—will all be demonstrated during closed-loop operation. Operator and engineering training will also be conducted during Phase 3.

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Anticipated Benefits In this project, Pegasus Technologies and NRG Texas are attempting to put together all of the required best-of-class artificial intelligence and simulation technologies to prove that mercury speciation and multi-pollutant reduction benefits can be measured, optimized, and controlled. If successful, Pegasus will demonstrate the capability of sophisticated control processes and advanced sensor technologies to simultaneously reduce harmful emissions of mercury and increase plant efficiency. Increased control of SO2, NOX, and particulate matter should also result, along with a reduction in water usage. Since these technologies are designed to control and optimize all major facets of power plant operations, the demonstration is expected to provide the capability to maximize plant efficiency for electricity production while reducing mercury emissions. This project is also expected to address concerns that higher mercury concentrations in existing by-products, such as ash, may adversely affect the commercial value of those by-products. This project should demonstrate an operating environment that simultaneously offers higher-than-average compliance with environmental requirements and better control of emissions, resulting in both a smaller risk of non-compliance to the utility and minimization of capital expenditures. In general, the project is expected to demonstrate how integrating sensors and advanced controls into a total plant solution can lead to improved economics

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while being environmentally compliant. The technologies being demonstrated are expected to have widespread application since they can be directly retrofitted to the existing coal fleet or integrated into future new plant designs.

DEMONSTRATION OF INTEGRATED OPTIMIZATION SOFTWARE AT THE BALDWIN ENERGY COMPLEX PROJECT Introduction

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As part of the CCPI, sophisticated computational techniques are being applied to an Illinois coal-fired power plant to show how new technology can increase power plant efficiency and reliability and reduce air emissions. NeuCo, Inc., of Boston, MA, is designing and demonstrating an integrated online optimization system at the Dynegy Midwest Generation power plant located in Baldwin, IL. The Baldwin Energy Complex (BEC) consists of two 585 MW cyclone-fired boilers with selective catalytic reduction (SCR) and a 595 MW tangentially fired boiler with low NOX burners. The five system optimization modules being developed include cyclone combustion, sootblowing, SCR operations, overall unit thermal performance, and maintenance optimization. This project builds on the NeuCo proprietary ProcessLink® technology platform. Power plants operate in many different conditions and plant processes are highly complex and interrelated. The goal of optimization is to continuously assess and adjust (or provide actionable advice about) the settings of the many variables affecting plant performance so that the optimal balance of plant emissions, fuel efficiency, capacity, and reliability is achieved. The total cost of this 45-month project is estimated at $19 million, including a 45 percent DOE cost share.

Dynegy Midwest Generation‘s Baldwin Energy Complex

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The Baldwin Energy Power Plant at sunset

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Project Objectives The overall objective of applying integrated optimization software is to improve the emissions profile, efficiency, maintenance requirements, and plant asset life for coal-based power generation in order to extend the use of abundant coal resources in the United States in an environmentally sound manner. In general, software optimization offers several advantages to power plants, including the ability to control key parameters on a consistent basis, compensate for changes in coal quality, optimize controls to meet specific plant objectives, and help in understanding the available data and its use for improved operations. The project at BEC will demonstrate and quantify the environmental and emissions benefits associated with deployment of a fully integrated set of software solutions for optimization of plant performance for coal-fired power generation. Because retrofits, repowering, modifications, and new technologies are steadily increasing the complexity of modern power plants, an integrated process-optimization approach is required to maximize equipment performance and minimize operating costs. Optimization solutions are now available for a variety of power plant control systems; linking these systems together will provide overall plant-level optimization that is expected to yield additional benefits. Therefore, the primary objective of this project is to demonstrate integration of existing controls and control systems, sensors, and computer hardware with advanced optimization techniques at BEC and to link the individual optimization modules through the NeuCo ProcessLink® platform. Collectively, these modules are expected to provide optimization solutions for this 1,765 MW coal-fired power plant by reducing emissions, increasing plant efficiency, and increasing the availability of the plant for power generation.

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Project Description

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NeuCo is designing and demonstrating an integrated online optimization software system for the Dynegy Midwest Generation power plant using advanced computational techniques that are expected to achieve peak performance from the three coal-fired units at the energy complex. NeuCo is using its ProcessLink® technology platform of neural networks, expert systems (heuristics), first principle models, advanced algorithms, and fuzzy logic to maximize performances from the power plant combustor, soot removal system, and emission controls— the first time that all of these modules have been integrated into a computerized process network. Five separate modules are being designed and demonstrated by NeuCo at BEC and then integrated to provide unified plant optimization. CombustionOpt® uses neural network-based optimization, model predictive control, and other technologies to extract knowledge about the combustion process, determine the optimal balance of fuel and air flows in the furnace, and respond to changing conditions. CombustionOpt directly adjusts the distributed control system to more consistently position the dampers, burner tilts, overfire air, and other controllable parameters at their optimal settings for given sets of conditions, objectives, and constraints. This module should reduce fuel consumption and NOX emissions; it should also improve carbon monoxide control, reduce opacity, and improve loss on ignition. SootOpt® optimizes sootblowing to reduce adverse fouling conditions and unplanned outages that soot and sootblowing can cause. It also expands efficiency improvements, reduces emissions, and drives boiler-cleaning actions toward optimal plant heat rate, emissions, and reliability goals. The SootOpt adaptive neural network models identify the equipment and actions most effective for achieving plant efficiency, reliability, and emissions objectives, and then bias control activity toward those objectives. The neural models work within boundaries defined by expert rules to ensure all applicable unit-specific constraints are considered. SCR-Opt® uses neural-network-based optimization, model predictive control, and other technologies to make the operation of the SCR as efficient as possible. SCROpt is expected to minimize ammonia usage and reduce NOX emissions. PerformanceOpt® uses a rigorous, first-principles-based thermodynamic model of the boiler and steam cycle to conduct both ―what is‖ and ―what if‖ simulations of unit operations. Continuously monitoring the actual versus the expected performance levels of key equipment and process conditions, PerformanceOpt detects when performance deviates from what is achievable under current operating conditions and calculates the impact of that deviation so that remedial actions can be prioritized. PerformanceOpt is expected to improve heat rate, steam temperatures, and generating capacity. MaintenanceOpt™ helps engineers manage the entire life-cycle of reliability, capacity, and efficiency problems more efficiently and effectively. It uses neural network technology to constantly search for gaps between actual and expected behavior across a broad range of process and equipment health variables. Its

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Klaes G. Douwe powerful diagnostics knowledge base also helps to filter false alarms, determine the root causes and corrective actions of identified problems, and aid in problem resolution and tracking. MaintenanceOpt is expected to increase annual power output and assist in providing lower costs of electricity to the consumer.

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These advanced computational capabilities will be used to comprehensively optimize a variety of systems within BEC by using existing control technologies and then linking these systems to each other. This innovative project will provide solutions that use system-specific optimization applications as data sources and actuators. In general, the overall architecture of this control platform is designed to permit flexible deployment strategies. Rather than requiring that all data and logic reside on a single computer, the service model allows applications to leverage networked computational resources. The application architecture is built around interoperable services that should result in more efficient plant operations. The planned integration concept is shown below. This integrated optimization software project at BEC consists of two phases. Phase I, which has been completed, entailed the development and installation of initial versions of each of the five optimization modules, as well as their integration through the ProcessLink platform to address the full scope of plant operations and relevant system interactions. Extensive operating experience will be required to quantify the benefits associated with control system optimization. The goal during Phase I was to establish each system and demonstrate its role in unified plant optimization. Phase I activities focused on developing, deploying, integrating, and testing prototypes for each of the five optimization modules; identifying and addressing issues required for the modules to integrate with plant operations; and systematically collecting and assimilating feedback to improve subsequent module releases.

Control Room at the Baldwin

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Planned Integration Concept for the Baldwin Energy Complex

The goal of Phase II is to improve upon the software installed and tested in Phase I and to perform rigorous analysis of operating data in order to quantify the benefits of the integrated system. Phase II entails quantification of results at BEC; refinement of the software installed and demonstrated in Phase I to support additional commercial releases of the five products; installation and beta testing at BEC; and commercialization of the solutions, taking into account both what is learned at BEC and feedback systematically incorporated from other operators of U.S. coal-fired power generation plants. During both phases, best practices iterative software development methods will be applied toward integration, full-scale demonstration, and eventual commercialization of these five solutions. All system software engineering, applications engineering, and systems integration will proceed through a multi-step, iterative process that supports a structured, modular approach to determining software and hardware requirements and functional definitions along with various design, development, test, installation, and startup activities. This iterative development process is specifically designed to deploy a commercially viable product as soon as possible, while at the same time applying host-site feedback and what is learned toward maximizing functionality and benefits in subsequent releases.

Anticipated Benefits This optimization initiative is expected to reduce NOX emissions by 5 percent and increase thermal efficiency by 1.5 percent. The increased thermal efficiency is expected to reduce emissions of CO2, mercury, and particulates. Ammonia consumption is expected to be reduced by 15 percent, accompanied by a one-year extension of the SCR catalyst. The optimization initiative is expected to also result in improved power plant capacity and reliability which, in turn, is expected to increase net annual electrical power production by 1.5 percent. Consumers should benefit through lower electricity costs.

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The NeuCo ProcessLink® architecture offers plant operators a highly flexible control system platform. Optimization modules can be designed and applied to individual subsystems in a plant, leveraging existing sensors, actuators, and networked computational resources— and then linking them to other individual subsystems to provide overall plant-level integration of controls responsive to plant operator and corporate criteria. This integrated process optimization approach will likely be an important tool for plant operators as plant complexity increases through retrofit and repowering applications, installation of new technologies, and plant modifications.

CONCLUSIONS

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The U.S. Department of Energy Clean Coal Technology programs continue to sponsor projects that develop technologies for optimizing power plant operation. These technologies help keep the cost of electricity low, reduce emissions, and conserve our fuel supply. The Lignite Fuel Enhancement project demonstrates a technology that reduces the moisture content of low-rank coals, which results in a number of benefits to power plant operation. Coal consumption is reduced, thereby reducing CO2 and other emissions. Parasitic power requirements are also reduced. When the technology is applied to new plants, capital costs will be reduced in several major subsystems, such as SO2 removal, pulverizers, and cooling towers. This technology achieves these benefits using only waste heat to remove the moisture from the fuel.

While the Neural Network-Intelligent Sootblower project did not reach all of its goals, the NN-ISB control system was found to be a sound idea with significant potential. The project successfully demonstrated a neural network, closed-loop operation on a full-scale boiler without causing unit upsets or violating any constraints—and also achieved operator acceptance. Although not yet completed, the Mercury Specie and Multi-Pollutant Control project and the Demonstration of Integrated Optimization Software project have demonstrated the ability of NN and AI technologies to provide significant economic, operational, and environmental benefits to power plant operation. The demonstrated technologies are

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applicable to all types of coal-fired boilers and do not require the purchase of major equipment. Given the benefits and relatively low cost, these types of technologies are likely to find a ready market. The continuing development of software to control overall power plant operation, or selected aspects of it, has shown substantial progress in optimizing power plant performance. These software packages allow operators to more easily stay within their emission limits while improving power plant efficiency and lowering the cost of power production. While doing so, the participants have produced products that are expected to find a substantial market both in the United States and abroad.

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BIBLIOGRAPHY Bullinger, Charles, Mark Ness & Nenad Sarunac. (2006). ―Coal Creek Prototype Fluidized Bed Coal Dryer: Performance Improvement, Emissions Reduction, and Operating Experience,‖ Paper presented at 31st International Technical Conference on Coal Utilization and Fuel Systems, Clearwater, Florida, May 21-25. Gollakota, Sai. (2007). ―Great River Energy Project Benefits Presentation.‖ Paper presented on February. Great River Energy. (2002). ―Great River Energy Lignite Fuel Enhancement Proposal to DOE Solicitation DE-PS26-02NT4142 8—Public Abstract,‖ August 1, http://www.netl.doe.gov/technologies/coalpower/cctc/ccpi/proposal-pdf/greabs.pdf. Ness, Mark, and Charles Bullinger. ―Pre-Drying the Lignite to CRE‟s Coal Creek Station.‖ May, 2005. NeuCo, Inc. (2006). Technical Progress Reports #11 to the U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. Cooperative Agreement DE-FC26-04NT41768. September 30. NeuCo, Inc. (2007). Technical Progress Report #12 to the U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. Cooperative Agreement DEFC26-04NT41768, February 5. Tampa Electric Company and Pegasus Technologies, Inc. (2005). “Project Performance and Review: Neural Network Based Intelligent Sootblowing System, Tampa Electric Company Big Bend Unit #2.‖ April U. S. Department of Energy. (2006). ―Clean Coal Technology Programs: Program Update 2006,‖ September pp. 3-54, http://www.netl.doe.gov/technologies/coalpower/cctc/ ccpi/pubs/2006_program_update.pdf. U. S. Department of Energy, Office of Fossil Energy & National Energy Technology Laboratory. (2005). ―Advanced Coal Conversion Process Demonstration: A DOE Assessment,‖ April, http://www.netl.doe.gov/technologies/coalpower/cctc/cctdp/ biblio graphy/demonstration/pdfs/rsbud/NETL-1217_as%20sent%20to%20OSTI.pdf. U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. (2005). ―Big Bend Power Station Neural Network-Intelligent Sootblower Optimization.‖ Project Brief, Sept.. http://www.netl.doe.gov/technologies/ coalpower/ cctc/ PPII/bibliography/demonstration/environmental/neural/bigbenddemo.pdf

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U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. (2006). ―Big Bend Power Station Neural Network-Intelligent Sootblower Optimization.‖ Project Fact Sheet, Dec.. http://www.netl.doe.gov/publications/ factsheets/ project/Proj233.pdf U. S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. (2006). ―Big Bend Power Station Neural Network-Sootblower Optimization: A DOE Assessment,‖ DOE/NETL-2006/1234, June. http://www.netl.doe.gov/ technologies/coalpower/cctc/PPII/bibliography/demonstration/environmental/neural/Big BendSootblowerPPA_Final_061306.pdf U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. (2004). ―Cleaner Air by the Numbers.‖ TechLine, March 17,. http://www.netl.doe.gov/publications/press/2004/tl_ccpi_neucoaward.html U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. (2006). ―Demonstration of Integrated Optimization Software at the Baldwin Energy Complex.‖ Project Brief, http://www.netl.doe.gov/technologies/coalpower/ cctc/ ccpi/bibliography/demonstration/environmental/ccpi_demo.html U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. (2006). ―Demonstration of Integrated Optimization Software at the Baldwin Energy Complex.‖ Project Fact Sheet, Dec.. http://www.netl.doe.gov/publications/ factsheets/project/Proj221.pdf. U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. (2002). ―DOE, Tampa Electric Sign Agreement to Add „Intelligent‟ Computer System to Florida Power Plant.‖ TechLine,August21,2002.TechLine, August 21,. http://www.netl.doe.gov/technologies/coalpower/cctc/PPII/bibliography/ demonstration/environmental/neural/neural_tech.pdf U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. (2006). ―Mercury Specie and Multi-Pollutant Control.‖ Project Brief,.http:// www.netl.doe.gov/technologies/coalpower/cctc/ccpi/project_briefs/CCPI_Pegasus.pdf. U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. (2006). ―Mercury Specie and Multi-Pollutant Control Project.‖ Project Fact Sheet, Dec. http://www.netl.doe.gov/publications/factsheets/project/Proj372.pdf U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory. (2004). ―Pegasus Project Selected as Part of Clean Coal Power Initiative.‖ October 28. TechLine. http://www.netl.doe.gov/publications/press2004/tl_ccpi2 _pegasus.html

ACRONYMS AND ABBREVIATIONS ACM AI APH BEC CCPI CCTDP

Advanced calibration monitor Artificial intelligence Air preheater Baldwin Energy Complex Clean Coal Power Initiative Clean Coal Technology Demonstration Program

Clean Coal Tech - Power Plant Optimization

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CO2 DOE ESP FGD FL FMS GRE ISB MW NETL NN NN-ISB NOx OPM PPII SCR SO2 TECO

Carbon dioxide Department of Energy Electrostatic precipitator Flue gas desulfurization Fuzzy logic Fuel management system Great River Energy Intelligent sootblowing Megawatt National Energy Technology Laboratory Neural network Neural network-intelligent sootblowing Nitrogen Oxides Online performance monitor Power Plant Improvement Initiative Selective catalytic reduction Sulphur dioxide Tampa Electric Company

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In: Clean Coal Editor: Klaes G. Douwe

ISBN: 978-1-60741-358-5 © 2010 Nova Science Publishers, Inc.

Chapter 4

COAL GASIFICATION HEARING - HAWKINS TESTIMONY David G. Hawkins

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SUMMARY Coal use today is responsible for large and mostly avoidable damages to human health and our water and land. Coal use in the future, along with other fossil fuels, threatens to wreak havoc with the earth‘s climate system. Because coal is so abundant, capture of carbon dioxide from industrial coal sources and geologic disposal (CCD) is essential to reconcile continued coal use with climate protection. Coal gasification is a current commercially demonstrated technology amenable to capture of carbon dioxide from the synthesis gas prior to combustion. New coal plants forecast to be built in the next 25 years, if not equipped with CCD, will emit 30 per cent more carbon dioxide in their operating lives than has been released from all prior human use of coal. We cannot afford to delay use of CCD on new coal plants. Fortunately, we know enough today to implement large scale CCD for coal plants now in the design stages. Properly selected and operated disposal sites can retain injected CO2 for the required long periods of time and CCD activities can be conducted safely if an effective regulatory regime is put in place to license and monitor operations. EPA has the legal authority to write such rules but needs to do so without further delay. Policies to limit CO2 emissions and set performance standards are essential to drive use of CCD at the required scale and pace. Such policies should be enacted in this Congress. Well designed measures can phase in CCD on new coal plants with only very modest impacts on retail electricity prices. Government support of initial large-scale injection projects can help speed deployment and build confidence. Finally, CCD is only one of several tools available to cut global warming emissions. The fastest and cheapest method remains energy efficiency, with increased reliance on renewable energy resources providing another essential tool.

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David G. Hawkins

Thank you for the opportunity to testify today on coal gasification and carbon capture technologies. My name is David Hawkins. I am Director of the Climate Center at the Natural Resources Defense Council (NRDC). NRDC is a national, nonprofit organization of scientists, lawyers and environmental specialists dedicated to protecting public health and the environment. Founded in 1970, NRDC has more than 1.2 million members and online activists nationwide, served from offices in New York, Washington, Los Angeles and San Francisco, Chicago and Beijing. Today, the U.S. and other developed nations around the world run their economies largely with industrial sources powered by fossil fuel and those sources release billions of tons of carbon dioxide (CO2) into the atmosphere every year. There is national and global interest today in capturing that CO2 for disposal or sequestration to prevent its release to the atmosphere, something that can be achieved with commercially demonstrated coal gasification systems. To distinguish this industrial capture system from removal of atmospheric CO2 by soils and vegetation, I will refer to the industrial system as carbon capture and disposal or CCD. The interest in CCD stems from a few basic facts. We now recognize that CO2 emissions from use of fossil fuel result in increased atmospheric concentrations of CO2, which along with other so-called greenhouse gases, trap heat, leading to an increase in temperatures, regionally and globally. These increased temperatures alter the energy balance of the planet and thus our climate, which is simply nature‘s way of managing energy flows. Documented changes in climate today along with those forecasted for the next decades, are predicted to inflict large and growing damage to human health, economic well-being, and natural ecosystems. Coal is the most abundant fossil fuel and is distributed broadly across the world. It has fueled the rise of industrial economies in Europe and the U.S. in the past two centuries and is fueling the rise of Asian economies today. Because of its abundance, coal is cheap and that makes it attractive to use in large quantities if we ignore the harm it causes. However, per unit of energy delivered, coal today is a bigger global warming polluter than any other fuel: double that of natural gas; 50 per cent more than oil; and, of course, enormously more polluting than renewable energy, energy efficiency, and, more controversially, nuclear power. To reduce coal‘s contribution to global warming, we must deploy and improve systems that will keep the carbon in coal out of the atmosphere, specifically systems that capture carbon dioxide (CO2) from coal- fired power plants and other industrial sources for safe and effective disposal in geologic formations.

THE TOLL FROM COAL Before turning to the status of CCD let me say a few words about coal use generally. The role of coal now and in the future is controversial due to the damages its production and use inflict today and skepticism that those damages can or will be reduced to a point where we should continue to rely on it as a mainstay of industrial economies. Coal is cheap and abundant compared to oil and natural gas. But the toll from coal as it is used today is enormous. From mining deaths and illness and devastated mountains and streams from practices like mountain top removal mining, to accidents at coal train crossings, to air

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emissions of acidic, toxic, and heat-trapping pollution from coal combustion, to water pollution from coal mining and combustion wastes, the conventional coal fuel cycle is among the most environmentally destructive activities on earth. Certain coal production processes are inherently harmful and while our society has the capacity to reduce many of today's damages, to date, we have not done so adequately nor have we committed to doing so. These failures have created well-justified opposition by many people to continued or increased dependence on coal to meet our energy needs. Our progress of reducing harms from mining, transport, and use of coal has been frustratingly slow and an enormous amount remains to be done. Today mountain tops in Appalachia are destroyed to get at the coal underneath and rocks, soil, debris, and waste products are dumped into valleys and streams, destroying them as well. Waste impoundments loom above communities (including, in one particularly egregious case, above an elementary school) and thousands of miles of streams are polluted. In other areas surface mine reclamation is incomplete, inadequately performed and poorly supervised due to regulatory gaps and poorly funded regulatory agencies. In the area of air pollution, although we have technologies to dramatically cut conventional pollutants from coal-fired power plants, in 2004 only one-third of U.S. coal capacity was equipped with scrubbers for sulfur dioxide control and even less capacity applied selective catalytic reduction (SCR) for nitrogen oxides control. And under the administration's so-called CAIR rule, even in 2020 nearly 30 per cent of coal capacity will still not employ scrubbers and nearly 45 per cent will lack SCR equipment. Moreover, because this administration has deliberately refused to require use of available highly effective control technologies for the brain poison mercury, we will suffer decades more of cumulative dumping of this toxin into the air at rates several times higher than is necessary or than faithful implementation of the Clean Air Act would achieve. Finally, there are no controls in place for CO2, the global warming pollutant emitted by the more than 330,000 megawatts of coal-fired plants; nor are there any CO2 control requirements adopted today for old or new plants save in California. Mr. Chairman and members of the committee, the environmental community has been criticized in some quarters for our generally negative view regarding coal as an energy resource. But consider the reasons for this. Our community reacts to the facts on the ground and those facts are far from what they should be if coal is to play a role as a responsible part of the 21st century energy mix. Rather than simply decrying the attitudes of those who question whether using large amounts of coal can and will be carried out in a responsible manner, the coal industry in particular should support policies to correct today's abuses and then implement those reforms. Were the industry to do this, there would be real reasons for my community and other critics of coal to consider whether their positions should be reconsidered.

THE NEED FOR CCD Turning to CCD, NRDC supports rapid deployment of such capture and disposal systems for sources using coal. Such support is not a statement about how dependent the U.S. or the world should be on coal and for how long. Any significant additional use of coal that vents its

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CO2 to the air is fundamentally in conflict with the need to keep atmospheric concentrations of CO2 from rising to levels that will produce dangerous disruption of the climate system. Given that an immediate world-wide halt to coal use is not plausible, analysts and advocates with a broad range of views on coal's role should be able to agree that, if it is safe and effective, CCD should be rapidly deployed to minimize CO2 emissions from the coal that we do use. Today coal use and climate protection are on a collision course. Without rapid deployment of CCD systems, that collision will occur quickly and with spectacularly bad results. The very attribute of coal that has made it so attractive—its abundance—magnifies the problem we face and requires us to act now, not a decade from now. Until now, coal‘s abundance has been an economic boon. But today, coal‘s abundance, absent corrective action, is more bane than boon. Since the dawn of the industrial age, human use of coal has released about 150 billion metric tons of carbon into the atmosphere—about half the total carbon emissions due to fossil fuel use in human history. But that contribution is the tip of the carbon iceberg. Another 4 trillion metric tons of carbon are contained in the remaining global coal resources. That is a carbon pool nearly seven times greater than the amount in our pre-industrial atmosphere. Using that coal without capturing and disposing of its carbon means a climate catastrophe. And the die is being cast for that catastrophe today, not decades from now. Decisions being made today in corporate board rooms, government ministries, and congressional hearing rooms are determining how the next coal-fired power plants will be designed and operated. Power plant investments are enormous in scale, more than $1 billion per plant, and plants built today will operate for 60 years or more. The International Energy Agency (IEA) forecasts that more than $5 trillion will be spent globally on new power plants in the next 25 years. Under IEA‘s forecasts, over 1800 gigawatt s (GW) of new coal plants will be built between now and 2030— capacity equivalent to 3000 large coal plants, or an average of ten new coal plants every month for the next quarter century. This new capacity amounts to 1.5 times the total of all the coal plants operating in the world today. The astounding fact is that under IEA‘s forecast, 7 out of every 10 coal plants that will be operating in 2030 don‘t exist today. That fact presents a huge opportunity—many of these coal plants will not need to be built if we invest more in efficiency; additional numbers of these coal plants can be replaced with clean, renewable alternative power sources; and for the remainder, we can build them to capture their CO2, instead of building them the way our grandfathers built them. If we decide to do it, the world could build and operate new coal plants so that their CO2 is returned to the ground rather than polluting the atmosphere. But we are losing that opportunity with every month of delay—10 coal plants were built the old-fashioned way last month somewhere in the world and 10 more old-style plants will be built this month, and the next and the next. Worse still, with current policies in place, none of the 3000 new plants projected by IEA are likely to capture their CO2. Each new coal plant that is built carries with it a huge stream of CO2 emissions that will likely flow for the life of the plant—60 years or more. Suggestions that such plants might be equipped with CO2 capture devices later in life might come true but there is little reason to count on it. As I will discuss further in a moment, while commercial technologies exist for pre-combustion capture from gasification-based power plants, most new plants are not using gasification designs and the few that are, are not incorporating capture systems. Installing

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capture equipment at these new plants after the fact is implausible for traditional coal plant designs and expensive for gasification processes. If all 3000 of the next wave of coal plants are built with no CO2 controls, their lifetime emissions will impose an enormous pollution lien on our children and grandchildren. Over a projected 60- year life these plants would likely emit 750 billion tons of CO2, a total, from just 25 years of investment decisions, that is 30% greater than the total CO2 emissions from all previous human use of coal. Once emitted, this CO2 pollution load remains in the atmosphere for centuries. Half of the CO2 emitted during World War I remains in the atmosphere today. In short, we face an onrushing train of new coal plants with impacts that must be diverted without delay. What can the U.S. do to help? The U.S. is forecasted to build nearly 300 of these coal plants, according to reports and forecasts published by the U.S. EIA. We should adopt a national policy that new coal plants be required to employ CCD without delay. By taking action ourselves, we can speed the deployment of CCD here at home and set an example of leadership. That leadership will bring us economic rewards in the new business opportunities it creates here and abroad and it will speed engagement by critical countries like China and India. To date our efforts have been limited to funding research, development, and limited demonstrations. Such funding can help in this effort if it is wisely invested. But government subsidies--which are what we are talking about--cannot substitute for the driver that a real market for low-carbon goods and services provides. That market will be created only when requirements to limit CO2 emissions are adopted. In this Congress serious attention is finally being directed to enactment of such measures.

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KEY QUESTIONS ABOUT CCD I started studying CCD in detail ten years ago and the questions I had then are those asked today by people new to the subject. Do reliable systems exist to capture CO 2 from power plants and other industrial sources? Where can we put CO2 after we have captured it? Will the CO2 stay where we put it or will it leak? How much disposal capacity is there? Are CCD systems ―affordable‖? To answer these questions, the Intergovernmental Panel on Climate Change (IPCC) decided four years ago to prepare a special report on the subject. That report was issued in September 2005 as the IPCC Special Report on Carbon Dioxide Capture and Storage. I was privileged to serve as a review editor for the report‘s chapter on geologic storage of CO2.

CO2 CAPTURE The IPCC special report groups capture or separation of CO2 from industrial gases into four categories: post-combustion; pre-combustion; oxyfuel combustion; and industrial separation. I will say a few words about the basics and status of each of these approaches. In a conventional pulverized coal power plant, the coal is combusted using normal air at atmospheric pressures. This combustion process produces a large volume of exhaust gas that

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contains CO2 in large amounts but in low concentrations and low pressures. Commercial post-combustion systems exist to capture CO2 from such exhaust gases using chemical ―stripping‖ compounds and they have been applied to very small portions of flue gases (tens of thousands of tons from plants that emit several million tons of CO2 annually) from a few coal-fired power plants in the U.S. that sell the captured CO2 to the food and beverage industry. However, industry analysts state that today‘s systems, based on publicly available information, involve much higher costs and energy penalties than the principal demonstrated alternative, pre-combustion capture. New and potentially less expensive post-combustion concepts have been evaluated in laboratory tests and some, like ammonia-based capture systems, are scheduled for small pilotscale tests in the next few years. Under normal industrial development scenarios, if successful such pilot tests would be followed by larger demonstration tests and then by commercialscale tests. These and other approaches should continue to be explored. However, unless accelerated by a combination of policies, subsidies, and willingness to take increased technical risks, such a development program could take one or two decades before postcombustion systems would be accepted for broad commercial application. Pre-combustion capture is applied to coal conversion processes that gasify coal rather than combust it in air. In the oxygen-blown gasification process coal is heated under pressure with a mixture of pure oxygen, producing an energy-rich gas stream consisting mostly of hydrogen and carbon monoxide. Coal gasification is widely used in industrial processes, such as ammonia and fertilizer production around the world. Hundreds of such industrial gasifiers are in operation today. In power generation applications as practiced today this ―syngas‖ stream is cleaned of impurities and then burned in a combustion turbine to make electricity in a process known as Integrated Gasification Combined Cycle or IGCC. In the power generation business, IGCC is a relatively recent development—about two decades old and is still not widely deployed. There are two IGCC power-only plants operating in the U.S. today and about 14 commercial IGCC plants are operating, with most of the capacity in Europe. In early years of operation for power applications a number of IGCC projects encountered availability problems but those issues appear to be resolved today, with Tampa Electric Company reporting that its IGCC plant in Florida is the most dispatched and most economic unit in its generating system. Commercially demonstrated systems for pre-combustion capture from the coal gasification process involve treating the syngas to form a mixture of hydrogen and CO2 and then separating the CO2, primarily through the use of solvents. These same techniques are used in industrial plants to separate CO2 from natural gas and to make chemicals such as ammonia out of gasified coal. However, because CO2 can be released to the air in unlimited amounts under today‘s laws, except in niche applications, even plants that separate CO2 do not capture it; rather they release it to the atmosphere. Notable exceptions include the Dakota Gasification Company plant in Beulah, North Dakota, which captures and pipelines more than one million tons of CO2 per year from its lignite gasification plant to an oil field in Saskatchewan, and ExxonMobil‘s Shute Creek natural gas processing plant in Wyoming, which strips CO2 from sour gas and pipelines several million tons per year to oil fields in Colorado and Wyoming. Today‘s pre-combustion capture approach is not applicable to the installed base of conventional pulverized coal in the U.S. and elsewhere. However, it is ready today for use with IGCC power plants. The oil giant BP has announced an IGCC project with pre-

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combustion CO2 capture at a site in California. When operational the project will gasify petroleum coke, a solid fuel that resembles coal more than petroleum to make electricity for sale to the grid. The captured CO2 will be sold to an oil field operator in California to enhance oil recovery. The principal obstacle for broad application of pre-combustion capture to new power plants is not technical, it is economic: under today‘s laws it is cheaper to release CO2 to the air rather than capturing it. Enacting laws to limit CO2 pollution can change this situation, as I discuss later. While pre-combustion capture from IGCC plants is the approach that is ready today for commercial application, it is not the only method for CO2 capture that may emerge if laws creating a market for CO2 capture are adopted. I have previously mentioned post-combustion techniques now being explored. Another approach, known as oxyfuel combustion, is also in the early stages of research and development. In the oxyfuel process, coal is burned in oxygen rather than air and the exhaust gases are recycled to build up CO2 concentrations to a point where separation at reasonable cost and energy penalties may be feasible. Small scale pilot studies for oxyfuel processes have been announced. As with post-combustion processes, absent an accelerated effort to leapfrog the normal commercialization process, it could be one or two decades before such systems might begin to be deployed broadly in commercial application. Given the massive amount of new coal capacity scheduled for construction in the next two decades, we cannot afford to wait until we see if these alternative capture systems prove out, nor do we need to. Coal plants in the design process today can employ proven IGCC and precombustion capture systems to reduce their CO2 emissions by about 90 percent. Adoption of policies that set a CO2 performance standard now for such new plants will not anoint IGCC as the technological winner since alternative approaches can be employed when they are ready. If the alternatives prove superior to IGCC and pre-combustion capture, the market will reward them accordingly. As I will discuss later, adoption of CO2 performance standards is a critical step to improve today‘s capture methods and to stimulate development of competing systems. I would like to say a few words about so-called ―capture-ready‖ or ―capture-capable‖ coal plants. Some years ago I was under the impression that some technologies like IGCC, initially built without capture equipment could be properly called ―capture-ready.‖ However, the implications of the rapid build-out of new coal plants for global warming and many conversations with engineers since then have educated me to a different view. Unfortunately, the term ―capture- ready‖ has been embraced by industry lobbyists in a manner that strips the concept of any meaning. According to some industry representatives, a power plant that simply leaves physical space for an unidentified black box deserves to be called ―captureready.‖ If that makes a power plant ―capture-ready‖ Mr. Chairman, then my driveway is ―Ferrari-ready.‖ We should not be investing today in coal plants at more than a billion dollars apiece with nothing more than a hope that some kind of capture system will turn up. We would not get on a plane to a destination if the pilot told us there was no landing site but options were being researched. It is correct that an IGCC unit built without capture equipment can be equipped later with such equipment and at much lower cost than attempting to retrofit a conventional pulverized coal plant with today‘s demonstrated post-combustion systems. However, the costs and engineering reconfigurations of such an approach are substantial. More importantly, we need to begin capturing CO2 from new coal plants without delay in order to keep global warming

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from becoming a potentially runaway problem. Given the pace of new coal investments in the U.S. and globally, we simply do not have the time to build a coal plant today and think about capturing its CO2 down the road.

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GEOLOGIC DISPOSAL We have a significant experience base for injecting large amounts of CO2 into geologic formations. For several decades oil field operators have received high pressure CO2 for injection into fields to enhance oil recovery, delivered by pipelines spanning as much as several hundred miles. Today in the U.S. a total of more than 35 million tons of CO2 are injected annually in more than 70 projects. (Unfortunately, due to the lack of any controls on CO2 emissions, about 80 per cent of that CO2 is comes from natural CO2 formations rather than captured from industrial sources. Historians will marvel that we persisted so long in pulling CO2 out of holes in the ground in order to move it hundreds of miles and stick in back in holes at the same time we were recognizing the harm being caused by emissions of the same molecule from nearby large industrial sources.) In addition to this enhanced oil recovery experience, there are several other large injection projects in operation or announced. The longest running of these, the Sleipner project, began in 1996. But the largest of these projects injects on the order of one million tons per year of CO2, while a single large coal power plant can produce about five million tons per year. And of course, our experience with man-made injection projects does not extend for the thousand year or more period that we would need to keep CO2 in place underground for it to be effective in helping to avoid dangerous global warming. Accordingly, the public and interested members of the environmental, industry and policy communities rightly ask whether we can carry out a large scale injection program safely and assure that the injected CO2 will stay where we put it. Let me summarize the findings of the IPCC on the issues of safety and efficacy of CCD. In its 2005 report the IPCC concluded the following with respect to the question of whether we can safely carry out carbon injection operations on the required scale: ―With appropriate site selection based on available subsurface information, a monitoring programme to detect problems, a regulatory system and the appropriate use of remediation methods to stop or control CO2 releases if they arise, the local health, safety and environment risks of geological storage would be comparable to the risks of current activities such as natural gas storage, EOR and deep underground disposal of acid gas.‖

The knowledge exists to fulfill all of the conditions the IPCC identifies as needed to assure safety. While EPA has authority regulate large scale CO2 injection projects its current underground injection control regulations are not designed to require the appropriate showings for permitting a facility intended for long-term retention of large amounts of CO2. With adequate resources applied, EPA should be able to adopt the necessary revisions to its rules in one to two years. While EPA has announced its intention to issue a proposed rule this year, intense oversight by Congress is likely to be needed to assure this happens.

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Do we have a basis today for concluding that injected CO2 will stay in place for the long periods required to prevent its contributing to global warming? The IPCC report concluded that we do, stating:

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―Observations from engineered and natural analogues as well as models suggest that the fraction retained in appropriately selected and managed geological reservoirs is very likely to exceed 99% over 100 years and is likely to exceed 99% over 1,000 years.‖

Despite this conclusion by recognized experts there is still reason to ask what are the implications of imperfect execution of large scale injection projects, especially in the early years before we have amassed more experience? Is this reason enough to delay application of CO2 capture systems to new power plants until we gain such experience from an initial round of multi-million ton ―demonstration‖ projects? To sketch an answer to this question, my colleague Stefan Bachu, a geologist with the Alberta Energy and Utilities Board, and I wrote a paper for the Eighth International Conference on Greenhouse Gas Control Technologies in June 2006. The obvious and fundamental point we made is that without CO2 capture, new coal plants built during any ―delay and research‖ period will put 100 per cent of their CO2 into the air and may do so for their operating life if they were ―grandfathered‖ from retrofit requirements. Those releases need to be compared to hypothetical leaks from early injection sites. Our conclusions were that even with extreme, unrealistically high hypothetical leakage rates from early injection sites (10% per year), a long period to leak detection (5 years) and a prolonged period to correct the leak (1 year), a policy that delayed installation of CO2 capture at new coal plants to await further research would result in cumulative CO2 releases twenty times greater than from the hypothetical faulty injection sites, if power plants built during the research period were ―grandfathered‖ from retrofit requirements. If this wave of new coal plants were all required to retrofit CO2 capture by no later than 2030, the cumulative emissions would still be four times greater than under the no delay scenario. I believe that any objective assessment will conclude that allowing new coal plants to be built without CO2 capture equipment on the ground that we need more large scale injection experience will always result in significantly greater CO2 releases than starting CO2 capture without delay for new coal plants now being designed. The IPCC also made estimates about global storage capacity for CO2 in geologic formations. It concluded as follows: ―Available evidence suggests that, worldwide, it is likely that there is a technical potential of at least about 2,000 GtCO2 (545 GtC) of storage capacity in geological formations. There could be a much larger potential for geological storage in saline formations, but the upper limit estimates are uncertain due to lack of information and an agreed methodology.‖

Current CO2 emissions from the world‘s power plants are about 10 Gt (billion metric tons) per year, so the IPCC estimate indicates 200 years of capacity if power plant emissions did not increase and 100 years capacity if annual emissions doubled.

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POLICY ACTIONS TO SPEED CCD As I stated earlier, research and development funding is useful but it cannot substitute for the incentive that a genuine commercial market for CO2 capture and disposal systems will provide to the private sector. The amounts of capital that the private sector can spend to optimize CCD methods will almost certainly always dwarf what Congress will provide with taxpayer dollars. To mobilize those private sector dollars, Congress needs a stimulus more compelling than the offer of modest handouts for research. Congress has a model that works: intelligently designed policies to limit emissions cause firms to spend money finding better and less expensive ways to prevent or capture emissions. Where a technology is already competitive with other emission control techniques, for example, sulfur dioxide scrubbers, a cap and trade program like that enacted by Congress in 1990, can result in more rapid deployment, improvements in performance, and reductions in costs. Today‘s scrubbers are much more effective and much less costly than those built in the 1980s. However, a CO2 cap and trade program by itself may not result in deployment of CCD systems as rapidly as we need. Many new coal plant design decisions are being made literally today. Depending on the pace of required reductions under a global warming bill, a firm may decide to build a conventional coal plant and purchase credits from the cap and trade market rather than applying CCD systems to the plant. While this may appear to be economically rational in the short term, it is likely to lead to higher costs of CO2 control in the mid and longer term if substantial amounts of new conventional coal construction leads to ballooning demand for CO2 credits. Recall that in the late 1990‘s and the first few years of this century, individual firms thought it made economic sense to build large numbers of new gas-fired power plants. The problem is too many of them had the same idea and the resulting increase in demand for natural gas increased both the price and volatility of natural gas to the point where many of these investments are idle today. Moreover, delaying the start of CCD until a cap and trade system price is high enough to produce these investments delays the broad demonstration of the technology that the U.S. and other countries will need if we continue substantial use of coal as seem likely. The more affordable CCD becomes, the more widespread its use will be throughout the world, including in rapidly growing economies like China and India. But the learning and cost reductions for CCD that are desirable will come only from the experience gained by building and operating the initial commercial plants. The longer we wait to ramp up this experience, the longer we will wait to see CCD deployed here and in countries like China. Accordingly, we believe the best policy package is a hybrid program that combines the breadth and flexibility of a cap and trade program with well-designed performance measures focused on key technologies like CCD. One such performance measure is a CO 2 emissions standard that applies to new power investments. California enacted such a measure in SB 1368 last year. It requires new investments for sale of power in California to meet a performance standard that is achievable by coal with a moderate amount of CO2 capture. Another approach is a low-carbon generation obligation for coal-based power. Similar in concept to a renewable performance standard, the low-carbon generation obligation requires an initially small fraction of sales from coal-based power to meet a CO2 performance standard that is achievable with CCD. The required fraction of sales would increase gradually over

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time and the obligation would be tradable. Thus, a coal-based generating firm could meet the requirement by building a plant with CCD, by purchasing power generated by another source that meets the standard, or by purchasing credits from those who build such plants. This approach has the advantage of speeding the deployment of CCD while avoiding the ―first mover penalty.‖ Instead of causing the first builder of a commercial coal plant with CCD to bear all of the incremental costs, the tradable low-carbon generation obligation would spread those costs over the entire coal-based generation system. The builder of the first unit would achieve far more hours of low- carbon generation than required and would sell the credits to other firms that needed credits to comply. These credit sales would finance the incremental costs of these early units. This approach provides the coal-based power industry with the experience with a technology that it knows is needed to reconcile coal use and climate protection and does it without sticker shock. A bill introduced last year, S. 309, contains such a provision. It begins with a requirement that one-half of one per cent of coal-based power sales must meet the low-carbon performance standard starting in 2015 and the required percentage increases over time according to a statutory minimum schedule that can be increased in specified amounts by additional regulatory action. A word about costs is in order. With today‘s off the shelf systems, estimates are that the production cost of electricity at a coal plant with CCD could be as much as 40% higher than at a conventional plant that emits its CO2. But the impact on average electricity prices of introducing CCD now will be very much smaller due to several factors. First, power production costs represent about 60% of the price you and I pay for electricity; the rest comes from transmission and distribution costs. Second, coal-based power represents just over half of U.S. power consumption. Third, and most important, even if we start now, CCD would be applied to only a small fraction of U.S. coal capacity for some time. Thus, with the trading approach I have outlined, the incremental costs on the units equipped with CCD would be spread over the entire coal-based power sector or possibly across all fossil capacity depending on the choices made by Congress. Based on CCD costs available in 2005 we estimate that a low-carbon generation obligation large enough to cover all forecasted new U.S. coal capacity through 2020 could be implemented for about a two per cent increase in average U.S. retail electricity rates.

RECENT CONGRESSIONAL ACTION Title VII of the Energy Independence and Security Act of 2007 (EISA) contains some provisions that, if funded, will help to make CCD a reality. These include authorizations to conduct at least seven large-scale geologic sequestration projects and separate authorizations for projects for large-scale capture of CO2 from industrial sources. A third provision requires the U.S. Geological Survey to carry out a comprehensive assessment of capacity for geologic disposal of CO2 . NRDC supports implementation of these provisions but we urge that they be complemented with enactment this year of a comprehensive program to cap CO2 and other greenhouse gases, along with complementary policies to accelerate CCD deployment. Enacting such a cap and trade bill will demonstrate the policy resolve to shift to lower-

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emitting energy investments, including CCD. That will help ensure that the demonstrations called for in EISA are integrated with commercial energy investments rather than being carried out with a science experiment mentality. It will also spur much more cost-effective cost-sharing arrangements with industry since these projects will help industry participants meet their obligations under a cap and trade program. As is shown by legislation like the Lieberman-Warner Climate Security Act, S. 2191, such comprehensive legislation can provide much larger resources to promote early CCD projects than the amounts authorized by EISA, even if the EISA funds were fully appropriated. NRDC believes that the large-scale projects in EISA should be implemented as an integral component of a policy to move forward with near-term deployment of CCD. New coal-fired power plants continue to be proposed in the U.S. and it is essential that any such plants should employ CCD. EISA‘s large-scale injection projects can serve as repositories for the CO2 produced by such plants. Thus, these projects should not be thought of as short-term operations that will be operated for a few years and then shut down. Any early ―demonstration‖ projects should be permitted by EPA for operation as permanent repositories. Such projects also should use anthropogenic CO2, as opposed to the use of naturally occurring or recycled CO2 used in most enhanced oil recovery projects today. Finally, I want to repeat the importance of prompt adoption of permitting and operational requirements for CO2 disposal by EPA. While EPA has announced an intention to propose rules this year, we encourage this Committee to work with the Environment and Public Works and the Appropriations Committees to assure that EPA adopts final rules in an expeditious manner.

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CONCLUSIONS To sum up, since we will almost certainly continue using large amounts of coal in the U.S. and globally in the coming decades, it is imperative that we act now to deploy CCD systems. Commercially demonstrated CO2 capture systems exist today and competing systems are being researched. Improvements in current systems and emergence of new approaches will be accelerated by requirements to limit CO2 emissions. Commercial deployment of such systems will only happen with enactment of comprehensive climate bills that cap CO2 and incorporate complementary policies to promote accelerate deployment of CCD. Geologic disposal of large amounts of CO2 is viable and we know enough today to conclude that it can be done safely and effectively. EPA must act without delay to revise its regulations to provide the necessary framework for efficient permitting, monitoring and operational practices for large scale permanent CO2 repositories. Finally CCD is an important strategy to reduce CO2 emissions from fossil fuel use but it is not the basis for a climate protection program by itself. Increased reliance on low-carbon energy resources is the key to protecting the climate. The lowest carbon resource of all is smarter use of energy; energy efficiency investments will be the backbone of any sensible climate protection strategy. Renewable energy will need to assume a much greater role than it does today. With today‘s use of solar, wind and biomass energy, we tap only a tiny fraction of the energy the sun provides every day. There is enormous potential to expand our reliance on

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these resources. We have no time to lose to begin cutting global warming emissions. Fortunately, we have technologies ready for use today that can get us started. Mr. Chairman, that completes my testimony, I will be happy to take any questions you or other committee members may have.

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In: Clean Coal Editor: Klaes G. Douwe

ISBN: 978-1-60741-358-5 © 2010 Nova Science Publishers, Inc.

Chapter 5

COAL GASIFICATION HEARING - STRAKEY TESTIMONY

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Joseph P. Strakey Thank you Mr. Chairman and Members of the Committee. I appreciate this opportunity to provide testimony on the Department of Energy‘s (DOE‘s) Coal Gasification Research and Development (R&D) Program. The economic prosperity of the United States over the past century has largely 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, positively contribute to national security, and provide for the economic welfare of its citizens. Coal gasification, when done in conjunction with carbon capture and storage (CCS), is one technology option that offers our Nation an attractive approach to utilize our indigenous fossil energy resources in a more efficient and environmentally sound manner for producing clean, affordable power from coal with dramatically reduced carbon emissions. Coal gasification with CCS can also reduce the carbon impact of using coal to produce ultra-clean fuels for the transportation sector, substitute natural gas (SNG) to heat our homes and fuel our industrial sector, fertilizers to ensure an abundant food supply, and chemicals that play an integral part in our every day lives. Another coal gasification concept that could further reduce carbon dioxide (CO2) emissions is co-feeding coal and biomass into gasifiers to produce electricity or conventional transportation fuels. The transportation fuels application is referred to as the coal-biomass-toliquids (CBTL) process. When combined with CCS, CBTL can reduce the greenhouse gas footprint of the fuel by 20% (compared to petroleum) with the addition of roughly 10-18% by weight biomass to the coal while remaining cost competitive at today‘s world oil prices Similar benefits in reduction of carbon emissions can be achieved by co-feeding coal and biomass for electricity generation in advanced gasification-based systems. Gasification-based processes are an efficient and environmentally friendly way to produce low-cost electricity, compared with other conventional coal-conversion processes.

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For power generation applications, gasification technology utilizes 30-50% less water and produces about one-half the amount of solid wastes as conventional power plants. By the very nature of the process, sulfur oxides, nitrogen oxides, mercury, particulates, and other emissions can be reduced to near-zero levels and gasification is often the least expensive approach for the capture of CO2. The gasification of coal dates back as far as the end of the eighteenth century, and by the middle of the nineteenth century the basic underlying principles of gasification were fairly well understood. The use of gasification was very prominent in the latter part of the nineteenth century and the first half of the twentieth century for the production of town gas for residential and industrial use. Although this application has nearly vanished, due to its displacement by inexpensive natural gas and petroleum, new applications evolved in the industrial and manufacturing sectors. Gasification is at the heart of many processes that offer industry low-cost, reliable, and highly-efficient options for meeting a host of market applications. Gasification-based systems are capable of utilizing all carbon-based feedstocks, either separately or in combination with one another, including coal, petroleum coke, biomass, municipal and hazardous wastes. In the gasification process, carbon-based feedstocks are converted in the gasifier in the presence of steam and oxygen at high temperatures and moderate pressure to synthesis gas, a mixture of carbon monoxide and hydrogen. The synthesis gas is cleaned of particulates, sulfur, ammonia, chlorides, mercury, and other trace contaminants to predetermined levels consistent with further downstream processing applications. At this point, various options exist for the utilization of the synthesis gas. In one option, Integrated Gasification Combined Cycle (IGCC) for the production of electricity, the cleaned synthesis gas is combusted in a highefficiency gas turbine/generator, and the heat from the turbine exhaust gas is extracted to produce steam to drive a steam turbine/generator. Furthermore, IGCC can be readily adapted for concentrating, capturing, and sequestering CO2. In addition to being used for power generation, a portion or all of the synthesis gas can be chemically shifted (by reaction with steam) to a mixture of hydrogen (H2) and CO2. Here the H2 and CO2 can be separated, with the hydrogen being used in the gas turbine or highly efficient fuel cells for the production of electricity in a carbon-constrained world, while the CO2 can be captured and sequestered. The shifted synthesis gas can also be processed in chemical reactors to produce high-quality transportation fuels, SNG, and chemicals. Gasification-based systems are the only advanced processes within the Department‘s research portfolio that are capable of co-producing both power as well as a wide variety of commodity and premium products to meet future market requirements. Today, there are nineteen gasification plants operating in the United States. Nine of these plants use natural gas to produce carbon monoxide and hydrogen for synthesis of chemicals and petroleum refining, four use petroleum-based liquids for chemicals production, and six operate using solid feedstocks, i.e., coal and/or petroleum coke. Of the six solid-feed gasification plants, two produce chemicals, three operate as IGCC power plants, and one produces SNG. The following are examples of gasification plants in operation in the United States today. The largest operating coal gasification plant in the United States is the Dakota Gasification Company‘s Great Plains Synfuels Plant in Beulah, North Dakota. This plant was constructed with a loan guarantee from the Department of Energy and began operation in 1984. The plant has a capacity for producing up to 170 million cubic feet per day of SNG

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from nearly 18,500 tons per day of North Dakota lignite from an adjacent mine. The SNG is injected into an existing natural gas distribution pipeline to the Midwest. It should be noted that while the plant was a technical success, it was not a financial success: in 1985 the project sponsors defaulted on the loan, due in part to falling natural gas prices at the time, and the US Treasury paid $1.550 billion to cover the guarantee. Eastman Chemical Company operates two coal gasifiers at its Kingsport, Tennessee, chemical complex. Approximately 1,200 tons per day of eastern bituminous coal is converted to synthesis gas that is used as the building blocks for nearly 75% of the chemical products produced at the plant. Many of the products from this plant find their way into every day household products such as scotch tape, screw driver handles, Kodak 35-mm film, and flat screen TV panels. In addition, products such as Tylenol® and NutraSweet® also have their origins in coal from this facility. The Coffeyville Resources Nitrogen Fertilizer plant located in Coffeyville, Kansas, is the only other solid-feed gasification plant focusing on chemicals production, namely ammonia and urea fertilizer. This plant began operation in 2000 and today is the lowest cost manufacturer of nitrogen-based fertilizer products in North America. Three IGCC power plants using solid feedstocks are in operation today in the United States – Tampa Electric‘s Polk Power Station in Tampa, Florida (250 MWe); SG Solutions Wabash River plant in West Terre Haute, Indiana (262 MWe); and Valero‘s Delaware Clean Energy Cogeneration project in Delaware City, Delaware (160 MWe). The Florida and Indiana projects both received federal cost-share through DOE‘s Clean Coal Technology Program. These two projects successfully demonstrated coal-fueled IGCC and have been instrumental in giving the utility industry confidence in IGCC technology and in generating commercial interest in IGCC deployment. The Department‘s Office of Fossil Energy (FE), which manages research efforts within the Gasification Program that are implemented by the National Energy Technology Laboratory, recognizes the complex energy and environmental challenges facing America today. To address these needs, FE has a core coal R&D program that provides for the development of affordable and environmentally effective technologies to use coal. This core coal R&D program includes not only the Coal Gasification Program but also the Advanced Research (advanced materials, sensors and controls, and computational modeling), Advanced Turbines, Carbon Sequestration, Fuel Cells, Hydrogen and Fuels, and Innovations for Existing Plants Programs. DOE is developing advanced gasification technologies to meet the most stringent environmental regulations in any state, and to facilitate the efficient capture of CO2 for subsequent sequestration – a pathway to ―near-zero atmospheric emission‖ coal-based energy. Gasification plants are complex systems that rely on a large number of interconnected processes and technologies. Advancements in the state-of-the-art, as well as development of novel approaches, could expand technical pathways and enable gasification to meet the demands of future markets while contributing to energy security. Technical Issues/Hurdles – A technical report prepared by the Gasification Program in July 2002, ―Gasification Markets and Technologies – Present and Future: An Industry Perspective,‖ specifically outlines key technology issues affecting the commercial acceptance and deployment of gasification-based processes. Our coal research efforts in gasification are aimed at addressing these key issues, and good progress continues to be made towards their

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resolution. Foremost at that time was the need to improve process reliability and reduce capital cost. More recently, our research has expanded to address the cost and integration of gasification, particularly IGCC, with CCS. Areas identified as significantly impacting process reliability included refractory wear, feed-injector life, and high-temperature measurement instrumentation. Areas targeted for capital cost reduction efforts included improved feeding systems capable of handling multiple feedstocks, lower cost air-separation technologies, and high-temperature gas cleaning capable of deep removal of all contaminants. Some of the significant research programs addressing these issues are described below.

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Ion Transport Membranes – Conventional cryogenic air-separation technologies used in today‘s gasification plants are both capital and energy intensive. Typically, the cryogenic air separation constitutes 12-15% of the cost of an IGCC plant and can consume upwards of 10% of its gross power output. A promising technology being developed today that offers significant potential for cost and parasitic power reductions are known as Ion Transport Membranes (ITM). This technology has been under development by the Department, in partnership with Air Products and Chemicals, Inc. (APCI), for nearly ten years. During this time, ITM technology has progressed from fundamental materials development to the operation of full-scale membranes and half-size modules in a 5 ton-per-day unit operating at APCI‘s Sparrows Point industrial gas facility near Baltimore, Maryland. Engineering analyses have consistently shown nearly a 35% reduction in the capital cost of the airseparation unit for an IGCC plant and nearly a one-point gain in thermal efficiency. To achieve maximum benefit, the ITM must be integrated with a gas turbine. The program is in its third phase of development that will culminate in the integrated testing of a 150 ton-perday process module with a gas turbine that will be located at an existing coal gasification site in 2010. Upon successful completion of this phase, plans are being discussed for further scale-up to a 1,500 to 2,000 ton-per-day prototype unit. High-Temperature Gas Cleanup – Removing sulfur and other impurities from coalderived gas in an IGCC plant generally accounts for 10-12% of the capital investment of the plant to meet recent emissions standards. It is recognized that deep-cleaning technologies are required to meet future near-zero emission standards from coal-fired power plants, as well as achieve the desired synthesis gas purity for the production of transportation fuels and chemicals. Technologies for such deep cleaning are available, but are very costly and inefficient due to their low temperature of operation. Development of innovative deepcleaning technologies that operate at process temperatures consistent with downstream processing applications, i.e., 400 to 900 degrees Fahrenheit, would provide significant benefits. Although several approaches are being investigated, the most advanced employs a high-temperature, zinc-based sorbent in a transport reactor. Over 3,000 hours of operation with this particular sorbent have recently been completed using coal-derived synthesis gas at Eastman Chemical Company. Planning is in progress for slipstream testing of a 50-MWe size unit at a commercial gasification site. Coal-Feed Pumps – The development of coal-feed pumps will reduce the cost and improve the efficiency of all gasification-based processes. They will also improve the economics of utilization of vast low-rank coal reserves. With DOE support, Stamet

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Incorporated successfully developed a single-stage rotary feed pump that has the capability of injecting high- moisture coal into the high-pressure gasifier – up to 1000 psig. In 2007, General Electric purchased Stamet for use with their gasifier technology to make their technology suitable for low-rank coal gasification. Concurrently, DOE was engaged with Pratt & Whitney Rocketdyne to also develop a coal-feed pump. Detailed design of a 400 tonper-day pump is in progress and testing is scheduled to begin in late Fiscal Year 2009.

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H2 and CO2 Separation Membranes – Today‘s technologies for CO2 removal impose significant impacts on the thermal efficiency and capital cost of IGCC plants. It is believed that this impact can be greatly reduced through the use of advanced technologies such as membranes for separation. Furthermore, cost-effective and efficient gas separation technologies are vital in any chemical process operation and will impact the overall cost of the system. For the production of hydrogen from coal, gas separation is required for the separation of the shifted synthesis gas stream into pure H2 and CO2 streams. Separation of hydrogen from shifted synthesis gas is a key unit operation of any gasification-based hydrogen production system. The Gasification Program and its partner, Eltron Research and Development Company, are pursuing the development of a dense metallic-based membrane to reduce the cost and increase the performance of hydrogen separation. This membrane has achieved nearly all of DOE‘s 2015 performance goals for membrane-based systems. The Fuels program is also working on hydrogen separation technologies. Coal/Biomass Gasification – The process for turning gasified coal and/or biomass into liquid transportation fuels is mature and commercially available, with technology improvements driven by the marketplace. However, the technology for co-feeding and gasifying coal-biomass mixtures is not commercially available. DOE‘s program includes development of technology for co-feeding and gasifying coal/biomass for electricity generation application. As with much of DOE‘s gasification program, DOE‘s FY 2009 coal/biomass research targets electricity generation applications, but could also be used by the private sector for other applications, such as production of transportation fuels. Co-feeding of coal and biomass up to about 20% by weight is well within the range of operability for largescale plants. Operators of the NUON IGCC plant in Buggenum, The Netherlands, successfully fed a mixture of coal and 30% (by weight) demolition wood into a high-pressure, entrained-flow gasifier. Gasification and Carbon Sequestration – DOE is taking a leadership role in the development of CCS technologies. The Carbon Sequestration Program is addressing the key challenges that confront the wide-scale deployment of capture and storage technologies through research on cost-effective capture technologies; monitoring, mitigation, and verification technologies to ensure permanent storage; permitting issues; liability issues; public outreach; and infrastructure needs. Gasification technology holds substantial promise as the best coal conversion technology option to utilize carbon capture technologies. The Gasification Program is aggressively pursuing developments to reduce the cost of carbon capture so that the cost of electricity to the public will result in an increase of less than 10% for new gasification-based energy plants.

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FutureGen – The Department's FutureGen program offers a key opportunity to validate gasification technology coupled with CCS in commercial settings. In light of recent proposals for over 30 gasification-based commercial coal plants throughout the United States, and the potential siting issues that may require these plants to have carbon capture capability, the restructured FutureGen focuses on multiple gasification technology demonstrations with CCS in commercial plant settings. With this new strategy, the Department will help fund the CCS portion of the demonstration unit of the overall plant, thereby limiting the Department‘s, and taxpayer‘s, cost exposure. This restructured approach allows DOE to maximize the role of private sector innovation, provide a ceiling on federal contributions, and accelerate the Administration's goal of increasing the use of clean energy technologies to help meet the steadily growing demand for energy while also mitigating greenhouse gas emissions. In today‘s business environment, markets and market drivers are changing at a rapid pace. Environmental performance is a much greater factor now than in previous years as emission standards tighten. In addition, the reduction of CO2 emissions is one of the major challenges facing industry in response to global climate change. To help meet these challenges, there is a need for more environmentally sound, flexible, efficient, and reliable systems that still meet the ever-present demand for higher profitability. Gasification is a technology that is poised to meet these requirements. Mr. Chairman, Members of the Committee, this completes my statement. I would be happy to take any questions you may have.

In: Clean Coal Editor: Klaes G. Douwe

ISBN: 978-1-60741-358-5 © 2010 Nova Science Publishers, Inc.

Chapter 6

POTENTIAL EXPORTS OF U.S. CLEAN COAL TECHNOLOGY Shannon Fraser and Stefan Osborne

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OVERVIEW The United States is a world leader in technology that allows coal to be burned for electricity production without excessive emissions of sulfur dioxide, nitrogen oxide, mercury, and particulate matter. To reduce overall emissions, the U.S. coal industry is developing specific technology that can be incorporated into coal-fired power plants. That technology will allow coal to be burned with lower emissions of carbon dioxide.The U.S. technological preeminence in this field presents san opportunity to export the equipment and to license the technology to countries such as China and India,where coal-fired electricity production is rising quickly. This paper estimates the potential for U.S.exports of existing clean coal technology (CCT) to a growing worldwide market. U.S. exports of CCT to Australia,Brazil, China, India, Mexico, New Zealand, South Africa, South Korea, and the European Union (EU)251 could amount to US$36 billion between now and 2030. The potential CCT exports are estimated using several assumptions about future demand for U.S.CCT in those countries.The first assumption is that all new coal-fired electricitygeneration capacity will incorporate CCT. A total estimated demand for CCT is derived by using the projections of the Energy Information Administration (EIA) for increased coal-fired electricity-generating capacity, combined with an estimate of the value of CCT equipment needed for one gigawatt of capacity. If all required CCT equipment were imported and if the United States maintained its current share of each country‘s current CCT imports,the projected demand for U.S. CCT equipment in those countries from 2003 to 2030 would be $36 billion. Specifically, China, India, and South Korea present the greatest value of U.S. CCT exports in this study, representing approximately $26 billion, $3.5 billion, and $3.2 billion, respectively. Australia, Brazil, Mexico, New Zealand, South Africa, and the EU 25 account for an additional $2.9 billion of growth.

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Worldwide Clean Coal Technology Demand

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There is a stark difference in the growth rates of electricity consumption between countries that are members of the Organization for Economic Cooperation and Development (OECD) and those that are not. According to the EIA,2 growth in electricity consumption will be much lower in OECD countries, such as Australia, New Zealand, the EU 25, and the United States. In the non-OECD countries of China and India,electricity consumption will more than triple by 2030 (see Figure 1). China currently consumes 1,671 billion kilowatt hours of energy,which is anticipated to increase to 5,971 billion kilowatt hours by 2030. Overall electricity consumption in India will grow from 519 billion kilowatt hours in 2003 to 1,730 billion kilowatt hours by 2030. Coal-red electricity-generating capacity is projected to increase by 546 gigawatts in China and 94 gigawatts in India, with those two countries representing 73 percent of projected worldwide electricity-generating capacity growth (see Figure 1). Because China‘s economy is expected to grow by 6 percent per year from 2003 to 2030 and India‘s by 5.4 percent per year, both of these coal-rich countries will greatly rely on their domestic energy resources to spur economic development. With this anticipated growth, China and India will require increased investments in mining operations, power plants, and power distribution systems. Furthermore, Africa, Brazil, Mexico, and South Korea will more than double their electricity consumption from 2003 to 2030. The increased demand for CCT equipment provides an opportunity for U.S. exporters to supply this rapidly growing market.

Source: EIA, International Energy Outlook 2006 (Washington, DC: EIA, 2006), Appendix A, Table A9). Figure 1. World Net Electricity Consumption, 2003 and 2030

The estimate of potential U.S. CCT exports relies on the following assumptions:

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All new coal-red facilities will incorporate clean coal technology and emissions abatement equipment. All coal-red facilities will be on the scale of a supercritical 402 megawatt (0.4 gigawatt) plant.3 The current market shares for CCT equipment for both the and the United States will continue in their current proportions to 2030. Coal-fired electricity generation in 2030 will be equal to EIA forecasts. In addition, the estimate is based on trade in equipment only. Therefore,sales of U.S.licenses of CCT equipment are not incorporated. Moreover, the estimate of U.S. market share of CCT is based on Harmonized Tariff Schedules (HTS) categories (listed in Table 3), although those categories cover equipment that is used both in CCT power plants and in other industrial applications.

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Analysis of Potential CCT Equipment Exports Worldwide, 2003–2030 Potential CCT exports are estimated using several assumptions about future demand for U.S. CCT in Australia, Brazil, China, India, Mexico, New Zealand, South Africa, South Korea, and the EU 25. In those countries, coal is used primarily for coal-fired power generation. Estimating the potential market for CCT technology in those countries requires an estimate of the total world demand for imported CCT equipment and an estimate of the U.S. market share for those imports. The potential market for CCT can be derived from the EIA‘s 2030 estimates of coal-fired electricity-generating capacity in those countries.4 Assuming that all of this new capacity will use CCT equipment and that all the CCT equipment must be imported,an estimate of the costs of CCT equipment per gigawatt is multiplied by the projected increased capacity to derive a total CCT market estimate. Table 1. Coal-Fired Generating Capacity in Gigawatts, 2003 and 2030 Country/Region Africa Australia and New Zealand Brazil China EU 25 India Mexico South Korea United States

2003 39 30 1 239 196 67 5 17 310

2030 53 39 6 785 198 161 9 49 457

Source: EIA, International Energy Outlook 2006 (Washington, DC: EIA, 20060, Appendix F, Table F$.

To estimate the U.S. market share of CCT equipment to each of those countries,assume that this future market share will be equal to the current market share. Current market share estimates are based on world trade data:Table 1 shows the EIA‘s projected increases in coalfired electricity-generating capacity for the countries that were analyzed.

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Estimated Cost of CCT Equipment: $300 Million per Gigawatt The cost of CCT equipment can be derived from the Department of Energy ‘s 1999 publication ―Market-Based Advanced Coal Power Systems‖5, which is the most recent estimate of costs of supercritical pulverized coal plants. Table 2 shows the equipment costs for a 0.4 gigawatt supercritical coal-fired power plant in 1998 dollars. Because the $100.2 million total cost refers to a 0.4 gigawatt facility, the cost of equipment per gigawatt in 1998 dollars totals $250 million, which is $298 million in 2005 dollars.6 Table 2. Costs of a 0.4 Gigawatt Supercritical Coal-Fired Power Plant (1998 dollars) Equipment Cost $ (millions) Supercritical boiler $60.7 Flue gas cleanup system $33.6 Ash and spent sorbent handling $5.9 system Total $100.2 Source: U.S. Department of Energy. ―Supercritical Pulverized Coal Plants.‘ in Market-Based Advanced Coal Power Systems. Appendex E, Page 22, May 1999.

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Table 3. Selected HTS Codes Code number HTS 840490

Description Auxiliary plant for use with boilers of heading 8402 or 8403 (for example, economizers, super-heaters, soot removerers, gas recoverers); condensers for steam or other vaper power units; parts thereof

HTS 841620

Furance burners for liquid fuel, pulverized solid fuel, or gas; mechanical stokers, including their mechanical grates, mechanical ash dischargers, and similar appliances

HTS 842139

Centrifuges, including centrifugal dryers; filtering or purifying machinery and apparatus for liquids or gases; parts thereof (including electrostatic precipitators and selective catalytic reductions systems)

HTS 842199

Centrifuges, including centrigugal dryers; filtering or purifying machinery and apparatus for liquids or gases; parts thereof

Source: U.S. Intetnational bychapter/0612c84.pdf.

Trade

Commission.

http://hotdocs.usitc.gov/docs/tata/hts/

Estimated U.S.Share of International CCT Exports:24.6 Percent 7 The HTS code is used to derive the potential exports of clean coal equipment used in supercritical coal-fired power plants (see Table 3).8 The HTS codes in Table 3 include (a)parts of coal-fired power plants that are used with boilers; (b) furnace burners for pulverized solid fuels; (c) filters and purifying machinery, including electrostatic precipitators and selective catalytic reduction units; and (d) other filter purifying machinery.

Potential Exports of U.S. Clean Coal Technology

207

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The nine countries that were analyzed (according to their high current and projected coal usage rates for power production)are listed in Table 1. The World Trade Atlas and the HTS codes noted in Table 3 were used to derive the U.S. imports and worldwide imports of CCT equipment for 2005, the most recent year for which data for all countries analyzed is available. Notably, the majority of Mexico‘s imported boilers, furnace burners, filters, and purifying systems for coal-fired power plants came from the United States.For the EU 25, the majority of its imported equipment came from South Africa, while South Africa‘s imported equipment came from Germany. China‘s primary trade partners for imported CCT equipment were Japan and Germany, while India imported the majority of its CCT equipment from Thailand and Germany (see Table 4). The percentage of CCT equipment imports from the United States to each of those countries in 2005 was derived by dividing the dollar amount of imports from the United States by the dollar amount of imports from the world. Of note, Mexico imported 72.9 percent of its CCT equipment from the United States, followed by South Korea, which imported 33.4 percent of its equipment from the United States (see Figure 2).

Source: World Trade Atlas. Figure 2. Percentage of CCT Equipment Imports Sourced from the United States in 2005

Total Worldwide Demand for CCT Equipment from 2003 to 2030: $254 billion The potential world market for CCT equipment for the countries analyzed was deduced by multiplying the projected increase in coal-red gigawatts from 2003 to 2030 (as noted in Figure 1) by the cost of one gigawatt of CCT equipment in 2005 dollars ($298 million). The resulting amount is a cumulative total of CCT equipment imports from 2003 to 2030 in millions of 2005 dollars. According to those assumptions, China would import $163 billion in CCT equipment worldwide from 2003 to 2030, and India‘s imports would total $28 billion from worldwide sources (see Figure 3).

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Shannon Fraser and Stefan Osborne

Source: International Trade Administration, U.S. Department of Energy, and World Trade Atlas. Figure 3. Total World Market for CCT Equipment, Cumulative, 2003–2030

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Table 4. Clean Coal Technology Equipment Imports in 2005 (Based on HTS Number, US$ Millions) Country

U.S. rank

Imports from the United States

Imports from the world

Australia and New Zealand

1

52.33

208.77

Brazil China EU 25

1 3 2

34.93 168.68 470.54

117.34 1,054.31 2,351.59

India

3

20.50

162.62

Mexico

1

290.35

398.22

South Africa South Korea Total

2 1

15.87 90.17 1,143.37

93.79 269.60 4,656.24

Source: ITA derived these numbers using the HTS codes and the World Trade Atlas database.

Cumulative U.S. CCT Exports from 2003 to 2030: $36 Billion The potential total U.S. market share for CCT equipment imports from 2003 to 2030 for each of the countries, was calculated by multiplying the potential world market for CCT equipment (as noted in Figure 3) by the current U.S. market share (as noted in Figure 2). The

Potential Exports of U.S. Clean Coal Technology

209

result was $36 billion. The analysis indicates that China could potentially import $26 billion from the United States in CCT equipment from 2003 to 2030 (see Figure 4). India and South Korea may each take in approximately $3 billion in U.S. CCT equipment. A similar methodology can be used to determine the cumulative U.S. CCT exports by 2015, which would be $15 billion.

Conclusion In light of predicted increases in coal use for electricity production worldwide between 2003 and 2030, as well as overall U.S. competitiveness in emissions abatement equipment and advanced coal- red power plants, China, India, and South Korea present the greatest value of U.S. exports of CCT in this study, representing approximately $26 billion, $3.5 billion, and $3.2 billion, respectively.9 Additional markets for growth in U.S. CCT exports include Australia, Brazil, Mexico, New Zealand, South Africa, and the EU 25, for a total of $2.9 billion.

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Shannon Fraser is an international trade specialist and Stefan Osborne is an economist in the Manufacturing and Services unit of the U.S. Department of Commerce‟s International Trade Administration.

Source: International Trade Administration, U.S. Department of Energy, and World Trade Atlas. Figure 4. Total U.S. Market for CCT Equipment, Cumulative, 2003–2030

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End Notes 1

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The countries of the EU 25 are those that were members as of May 1, 2004: Austria, Belgium, Cyprus, the Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Ireland, Italy, Latvia, Lithuania, Luxembourg, the Netherlands, Malta, Poland, Portugal, Slovakia, Spain, Sweden, and the United Kingdom. Currently the EU has 27 members. 2 Department of Energy, Energy Information Administration, 2006 International Energy Outlook, available on the Internet at http://tonto.eia.doe.gov/FTPROOT/forecasting 3 Supercritical plants allow for higher pressures and temperatures, thereby enabling higher combustion e ciencies compared with standard pulverized coal power plants. 4 The most recent data available for analysis are noted in EIA‘s International Energy Outlook 2006. 5 See Department of Energy, ―Natural Gas Combined Cycle ―H‖ Class Gas Turbine‖ in Market-Based Advanced Coal Power Systems Appendix E, Page 22, May 1999, www.fe.doe.gov/programs/powersystems/publications/ MarketBasedPowerSystems/appe.pdf. 6 The most recent data available for analysis is from 2005 and can be found in the World Trade Atlas database http://www.gtis. com/product.cfm?level=1&type=W. 7 This figure is derived from data obtained from the World Trade Atlas database. 8 Details of the HTS codes are found at http://hotdocs. usitc. gov/docs/tata/hts/bychapter/0612c84.pdf. 9 For assumptions, refer to the section titled ―Worldwide Clean Coal Technology Demand.‖

CHAPTER SOURCES

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The following chapters have been previously published: Chapter 1 – This is an edited, excerpted and augmented edition of a United States Congressional Research Service publication, Report Order Code RL34621, dated August 15, 2008. Chapter 2 – These remarks were delivered as Statements on Recent Advances in Clean Coal Technology, before the Committee on Energy and Natural Resources, U.S. Senate, dated August 1, 2007. Chapter 3 –This is an edited, excerpted and augmented edition of a Clean Coal Technology, Topical Report, dated September 2007. Chapter 4 - These remarks were delivered as Statement of David G. Hawkins, Director, Climate Center Natural Resources Defense Council, before the Subcommittee on Science, Technology, and Innovation, Committee on Commerce, Science, and Transportation, U.S. Senate, dated April 9, 2008. Chapter 5 - These remarks were delivered as Statement of Joseph P. Strakey, Chief Technology Officer, National Energy Technology Laboratory, U.S. Department of Energy, before the Subcommittee on Science, Technology, and Innovation, Committee on Commerce, Science, and Transportation, U.S. Senate, dated April 9, 2008. Chapter 6 - This is an edited, excerpted and augmented edition of a United States Department of Commerce International Trade Administration publication, dated November 2007.

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INDEX

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A absorption, 4, 6, 63, 64, 67 acceleration, 135, 148 accidents, 183 accounting, 17, 37 achievement, 45 acid, 16, 37, 44, 50, 57, 62, 189 acidic, 184 ACM, 165, 180 acoustic, 165, 167 activated carbon, 128 activation, 165 actuators, 176, 178 acute, 38 adjustment, 11 administration, 184 administrative, 24 AEP, 6, 14, 29, 139, 151 Africa, xi, 105, 106, 201, 202, 203, 205, 206, 207 age, 137, 185 agricultural, 136 agricultural sector, 136 aid, 176, 197 air, 7, 8, 13, 19, 28, 44, 45, 53, 55, 57, 61, 64, 79, 88, 91, 94, 95, 113, 137, 150, 154, 158, 159, 161, 173, 175, 183, 184, 185, 186, 187, 188, 190, 198 air emissions, 44, 173, 184 air pollutant, 19, 45, 53, 55 air quality, 13 air toxics, 44 Alabama, 84, 85 Alberta, 79, 190 algae, 73 Algeria, 65, 66 algorithm, 156 allies, 96 alloys, 49, 60

alternative, 15, 16, 22, 23, 53, 64, 77, 99, 101, 106, 119, 120, 123, 138, 147, 149, 185, 187, 188 alternative energy, 15, 22, 23, 53 alternatives, 15, 73, 102, 103, 106, 126, 129, 146, 188 ambient air, 161 amelioration, 20 amine, 4, 5, 45, 63, 100, 141 amines, 4, 63, 64 ammonia, 4, 5, 6, 64, 98, 100, 175, 187, 196, 197 ammonium, 5, 64 amnion, 98 anode, 58 anthropogenic, 19, 38, 193 ants, 12 Appalachian Mountains, 85 application, 10, 11, 13, 15, 50, 53, 54, 55, 69, 76, 94, 99, 101, 113, 141, 145, 151, 165, 168, 173, 176, 187, 188, 190, 195, 196, 199 Appropriations Committee, 79, 193 Aquifer, 65 Arkansas, 151 artificial intelligence, xi, 153, 155, 172 Artificial intelligence, 156, 180 ash, 56, 58, 91, 92, 94, 141, 154, 155, 158, 164, 168, 170, 171, 172, 204 Asia, 106, 135, 136 Asian, 183 assessment, 21, 57, 67, 75, 124, 140, 190, 192 assets, 104, 120, 133 assumptions, xi, 15, 111, 201, 202, 203, 205, 208 Atlas, 45, 205, 206, 207, 208 atmosphere, 2, 20, 37, 38, 61, 65, 94, 116, 128, 161, 183, 185, 186, 187 atmospheric pressure, 62, 64, 186 Atomic Energy Commission, 22, 24, 31 atoms, 57 attitudes, 184

214

Index

Australia, xi, 8, 65, 66, 72, 125, 150, 201, 202, 203, 206, 207 Austria, 208 authority, 30, 31, 71, 182, 189 automobiles, 51, 74, 75, 104 availability, 15, 16, 21, 37, 38, 44, 60, 76, 84, 94, 102, 109, 116, 117, 121, 135, 136, 139, 151, 154, 158, 161, 174, 187 average costs, 129 avoidance, 87

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B back, 5, 35, 44, 51, 63, 64, 73, 74, 76, 77, 81, 83, 84, 85, 92, 105, 119, 131, 133, 135, 142, 149, 162, 189, 196 balance-of-plant, 64 barriers, x, 42, 50, 54, 61, 102, 116, 134, 153 basic research, 23, 41, 96 behavior, 65, 146, 172, 175 Beijing, 183 Belgium, 208 benchmarks, 12 beneficial effect, 145 benefits, 5, 15, 19, 25, 39, 41, 58, 95, 97, 106, 130, 146, 147, 148, 152, 155, 161, 162, 167, 172, 174, 176, 177, 178, 195, 198 benign, 41, 128 bias, 175 bicarbonate, 5, 64 binding, 136 biodiesel, 73, 104 biofuels, 129 biomass, ix, 31, 75, 88, 90, 96, 97, 102, 103, 105, 106, 107, 112, 114, 130, 147, 151, 152, 193, 195, 196, 199 biota, 37 bipartisan, 71, 112 blackouts, 164 boilers, 7, 45, 63, 64, 161, 162, 165, 167, 168, 173, 179, 204, 205 bomb, 12, 22 bonds, 21, 170 Brazil, xi, 104, 201, 202, 203, 206, 207 breakdown, 17 Britain, 84 broad spectrum, 46, 48, 83 BTUs, 72, 92 building blocks, 106, 197 burn, 94, 95, 157 burning, 34, 35, 44, 93, 108, 111, 128, 158, 161, 162 bushes, 81 business environment, 200

business model, 50, 96 buyer, 130 by-products, 124, 154, 168, 169, 172 C calcium, 145 calibration, 165, 180 Canada, 30, 31, 36, 45, 46, 65, 66, 72, 79, 93 capital cost, 5, 9, 10, 29, 57, 58, 59, 62, 63, 91, 92, 94, 102, 105, 106, 107, 112, 113, 118, 148, 178, 198, 199 capital expenditure, 168, 172 Carbon, 2, 4, 6, 7, 8, 10, 11, 15, 19, 21, 27, 28, 29, 30, 32, 41, 42, 45, 46, 49, 53, 66, 98, 100, 105, 107, 109, 113, 115, 116, 135, 138, 152, 181, 186, 197, 199 carbon dioxide, ix, xi, 1, 2, 11, 12, 13, 16, 29, 34, 38, 41, 42, 43, 46, 47, 48, 49, 50, 71, 74, 76, 78, 86, 88, 90, 92, 93, 94, 95, 104, 111, 112, 113, 114, 115, 116, 117, 119, 120, 128, 132, 135, 136, 137, 139, 143, 144, 146, 151, 162, 182, 183, 195, 201 carbon monoxide, 6, 31, 43, 94, 105, 154, 175, 187, 196 case study, 23 cast, 185 catalyst, 6, 92, 94, 128, 141, 177 cattle, 81 cell, 43, 45, 58, 59 CH4, 128 chemical industry, 49, 106, 148 chemical properties, 64 chemical reactions, 92, 94 chemical reactor, 196 chemicals, ix, 41, 43, 95, 102, 103, 105, 106, 107, 119, 120, 124, 148, 187, 195, 196, 197, 198 China, xi, 2, 4, 28, 33, 34, 37, 72, 84, 107, 120, 125, 136, 186, 191, 201, 202, 203, 205, 206, 207 chloride, 162 chlorofluorocarbons, 38 citizens, 83, 195 civilian, 22 Clean Air Act, 6, 13, 29, 30, 40, 140, 184 Clean Coal Power Initiative, x, 41, 113, 135, 138, 141, 153, 159, 161, 180 clean energy, 42, 93, 97, 99, 134, 200 cleaning, 164, 175, 198 cleanup, 44, 55, 56, 85, 204 climate change, x, 2, 3, 4, 11, 17, 22, 23, 28, 31, 38, 43, 54, 62, 79, 101, 102, 103, 104, 107, 117, 120, 121, 127, 150 closed-loop, 105, 165, 166, 167, 172, 178 closure, 50

215

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Index coal, ix, x, xi, 1, 2, 3, 4, 5, 6, 7, 9, 11, 12, 13, 14, 16, coal liquefaction, 48 coal mine, 91 coal particle, 58 coal-burning, 35, 44, 158 codes, 156, 204, 205, 206, 208 coke, 90, 92, 96, 105, 113, 138, 188, 196 collaboration, 6, 38, 91, 148 Collaboration, 148 Colorado, 65, 72, 74, 187 combustion characteristics, 56 combustion processes, 4, 188 commercialization, x, 2, 4, 6, 7, 11, 12, 15, 20, 22, 23, 41, 50, 67, 86, 88, 96, 97, 99, 101, 136, 138, 177, 188 Committee on Appropriations, 30 commodities, 116 commodity, 24, 30, 106, 116, 143, 196 communication, 18, 30, 167 communities, 73, 184, 189 community, 26, 65, 111, 122, 184 compensation, 85 competition, 40, 88, 168 competitiveness, 60, 90, 102, 103, 148, 149, 207 complex interactions, 55 complex systems, 43, 197 complexity, 9, 92, 133, 174, 178 compliance, 17, 26, 38, 44, 45, 133, 140, 141, 142, 156, 168, 172 components, 3, 19, 37, 49, 61, 105, 116, 155, 164 composition, 128, 142, 169 compounds, 37, 57, 187 computational modeling, 197 computing, 42 concentration, 7 conception, 19 concrete, 12, 84 confidence, 26, 93, 105, 120, 182, 197 configuration, 61, 127 conflict, 185 congress, 30 Congress, 1, 2, 14, 17, 21, 22, 23, 26, 34, 35, 38, 40, 47, 48, 73, 75, 76, 96, 97, 104, 107, 111, 112, 115, 116, 117, 124, 130, 132, 136, 158, 182, 186, 189, 191, 192 Congressional Budget Office, 15, 29, 30 consensus, 34, 38 conservation, 23, 37, 48, 104, 145 Consolidated Appropriations Act, 19, 21, 30 constraints, 44, 82, 111, 134, 149, 165, 167, 171, 172, 175, 178

construction, 3, 5, 7, 9, 13, 15, 20, 25, 28, 34, 36, 45, 60, 64, 77, 84, 96, 102, 112, 129, 139, 140, 145, 152, 161, 188, 191 construction materials, 3 consultants, 48 consumers, 48, 53, 71, 78, 102, 111 consumption, 35, 36, 55, 58, 61, 62, 63, 105, 131, 140, 145, 155, 169, 175, 177, 178, 192, 202 contaminant, 58 contaminants, 5, 13, 63, 64, 144, 196, 198 contamination, 144 contingency, 143 contract prices, 131 contractors, 96 contracts, 21, 130 control, ix, 1, 3, 4, 5, 7, 11, 12, 15, 16, 25, 26, 42, 44, 45, 47, 49, 56, 61, 63, 64, 70, 74, 80, 84, 98, 99, 100, 105, 112, 119, 120, 128, 136, 141, 146, 147, 154, 156, 157, 161, 162, 164, 165, 167, 168, 169, 170, 172, 174, 175, 176, 178, 179, 184, 189, 191 convective, 159 conversion, 31, 95, 97, 99, 101, 120, 142, 147, 152, 187, 195, 199 cooling, 44, 57, 61, 62, 92, 118, 154, 161, 162, 178 corporations, 39 corrosion, 60, 64 cost effectiveness, 26 cost of power, 51, 55, 179 cost saving, 98 cost-effective, 9, 11, 12, 15, 35, 40, 42, 44, 52, 77, 95, 102, 108, 111, 114, 115, 127, 193, 199 cost-sharing, 193 covering, 54, 83, 106 CPI, x, 41, 138, 153, 159 credit, 21, 31, 99, 101, 128, 129, 151, 192 crops, 105 cross-sectional, 145 crowding out, 15 CRS, 24, 28, 29, 30, 31 crude oil, 22, 24, 130 cryogenic, 57, 59, 198 customers, 21, 31, 98, 100, 103, 108, 109, 110, 111, 113, 117, 119, 134 cycles, 7, 56, 57, 58, 60, 73 cyclone, 173 Cyprus, 208 Czech Republic, 208 D danger, 16 data communication, 171 data set, 171

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216

Index

database, 206, 208 deaths, 183 debates, 34 debt, 21, 129 decisions, 12, 39, 73, 76, 80, 108, 109, 111, 134, 170, 186, 191 definition, 78 degradation, 5, 20 Delaware, 197 delivery, 76, 110, 144, 151 demand curve, 112 Denmark, 208 density, 113 Department of Commerce, 207, 209 Department of Defense, 125 Department of Energy, x, 1, 10, 17, 18, 23, 30, 31, 34, 36, 49, 76, 98, 100, 104, 113, 114, 115, 138, 141, 153, 161, 163, 178, 179, 180, 181, 195, 196, 204, 206, 207, 208, 209 Department of Energy (DOE), x, 1, 10, 17, 153, 163 deposition, 145 deposits, 136, 164 depreciation, 109, 114, 126 desalination, 65 detection, 61, 190 developed nations, 183 developing countries, 33, 136 developing nations, 138 development policy, 109 deviation, 175 dioxins, 37 dispersion, 58 displacement, 196 distributed generation, 43 distribution, 21, 31, 67, 148, 192, 197, 202 diversity, 39, 104 dividends, 87, 89 division, 90, 91, 109, 168 dollar costs, 55 domestic resources, 112 downhole, 46 draft, 159 dream, 96 drying, xi, 63, 151, 153, 155, 158, 159, 161, 162 dumping, 184 duration, 9, 56, 169 dust, 52 E earth, ix, 37, 108, 115, 182, 184 eating, 91 economic development, 202

economic growth, 37 economic security, 75 economic welfare, 195 economics, 3, 9, 15, 65, 72, 80, 85, 87, 89, 90, 91, 141, 142, 148, 156, 161, 172, 198 economies of scale, 54, 123 ecosystems, 45, 183 electric energy, 111, 112 electric power, 39, 42, 51, 53, 74, 77, 86, 94, 115, 143, 158, 165, 169 electric utilities, 111, 131, 135, 148 electrons, 113 elementary school, 184 elephant, 12, 26 eligibility criteria, 26, 136, 137 embargo, 23 emission, ix, 13, 16, 27, 42, 53, 77, 87, 88, 101, 117, 127, 131, 138, 140, 141, 143, 146, 152, 155, 170, 175, 179, 191, 197, 198, 200 employees, 93, 104 encouragement, 96 endothermic, 92 energy consumption, 58 energy efficiency, 22, 37, 38, 102, 104, 106, 112, 182, 183, 193 Energy Independence and Security Act, x, 2, 21, 26, 192 Energy Information Administration, xi, 28, 33, 142, 201, 208 Energy Policy Act of 2005, 19, 41, 74, 140 energy supply, 33, 103, 110, 117 engagement, 186 Enhanced Oil Recovery, 6, 65 environment, 96, 111, 132, 156, 172, 183, 189 environmental control, 55, 86, 88, 140, 154, 162 environmental impact, 13, 35, 36, 38, 195 environmental issues, 44, 111 Environmental Protection Agency, 13 environmental regulations, 43, 112, 139, 158, 197 EPA, 13, 14, 15, 30, 49, 68, 87, 90, 137, 182, 189, 193 equilibrium, 63, 142 equity, 129 erosion, 158 estimating, 7, 29, 39, 53 Estonia, 208 ethanol, 97, 104, 121 Ethanol, 2 EU, xi, 150, 151, 201, 202, 203, 205, 206, 207, 208 Europe, 140, 183, 187 evolution, 60 examinations, 117 execution, 96, 190

217

Index exercise, 171 expenditures, 23, 31 expert systems, 156, 175 expertise, 40, 46, 48, 148 exports, xi, 201, 202, 203, 204, 207 exposure, 200 extraction, 65, 115

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F failure, 22, 24, 108, 111 false alarms, 176 family, 40 farming, 81 fear, 136 February, 11, 18, 20, 29, 30, 66, 115, 152, 179 federal government, 3, 17, 22, 24, 49, 78, 106, 116, 135 fee, 198 feedback, 10, 167, 176, 177 feeding, ix, 58, 195, 198, 199 feedstock, 31, 75, 102, 105, 106, 147, 149 feelings, 79 feet, 13, 77, 80, 113, 116, 196 fertilizer, 98, 100, 141, 187, 197 fertilizers, ix, 195 field trials, 161 film, 197 filters, 204, 205 finance, 47, 49, 192 financial support, 47, 50, 116, 150 financing, 11, 21, 106, 140 Finland, 208 firms, 11, 36, 46, 91, 191, 192 fish, 112 flame, 64, 158 flexibility, 16, 24, 43, 59, 61, 68, 141, 167, 169, 170, 191 flow, 61, 65, 141, 158, 159, 161, 162, 171, 185, 199 fluctuations, 130 flue gas, 5, 6, 7, 13, 14, 29, 35, 41, 44, 45, 60, 61, 62, 63, 64, 98, 100, 141, 146, 155, 158, 159, 162, 164, 168, 169, 170, 187 fluid, 29, 35, 58, 104, 118 fluidized bed, 161 focusing, 157, 197 food, ix, 63, 103, 187, 195 forecasting, 139, 208 fossil, ix, 11, 21, 31, 34, 36, 37, 38, 39, 40, 64, 75, 76, 77, 84, 107, 111, 112, 115, 146, 168, 182, 183, 185, 192, 193, 195

fossil fuel, ix, 11, 34, 36, 37, 38, 39, 40, 75, 76, 77, 84, 107, 111, 112, 115, 146, 168, 182, 183, 185, 193, 195 ffouling, 64, 95, 158, 164, 175 France, 208 fresh water, 103 Friedmann, 2 fuel cell, 35, 42, 56, 58, 59, 138, 196 fuel cycle, 184 fuel efficiency, 173 fuel management, 170, 171, 172 funding, 9, 10, 17, 19, 20, 22, 23, 31, 40, 47, 49, 52, 68, 79, 82, 85, 89, 93, 109, 113, 114, 116, 126, 131, 134, 135, 138, 141, 145, 150, 159, 186, 191 funds, x, 1, 21, 24, 60, 79, 126, 193 FutureGen, 7, 17, 18, 19, 20, 25, 26, 29, 31, 38, 42, 43, 44, 50, 59, 66, 85, 135, 138, 200 fuzzy logic, 157, 175 G games, 125 gas exploration, 91 gas separation, 199 gas turbine, 55, 56, 57, 58, 62, 196, 198 gases, 4, 5, 6, 7, 13, 35, 62, 107, 186, 188, 204 gasifier, 6, 29, 56, 58, 62, 91, 94, 105, 128, 196, 199 gasoline, 129 GCC, 10, 139 GDP, 31, 80 General Electric, 161, 199 generators, 14, 115, 127, 133, 137, 142, 143 genetic algorithms, 157 geochemical, 46 geology, 49 geothermal, 110, 112, 114 Germany, 6, 8, 66, 69, 205, 208 GHG, 29, 147, 148, 151, 152 global climate change, 23, 53, 78, 111, 133, 134, 200 global competition, 37 global warming, ix, 20, 34, 73, 75, 84, 182, 183, 184, 188, 189, 190, 191, 194 glycerin, 104 goals, x, 2, 13, 22, 23, 37, 38, 39, 40, 42, 44, 53, 55, 60, 63, 80, 84, 93, 103, 116, 152, 153, 154, 156, 163, 167, 168, 175, 178, 199 goods and services, 139, 186 government, 3, 4, 9, 15, 16, 17, 19, 21, 22, 23, 24, 26, 31, 40, 44, 48, 49, 52, 53, 56, 68, 69, 78, 96, 97, 104, 105, 106, 114, 116, 131, 135, 138, 141, 148, 149, 150, 151, 152, 153, 158, 185, 186 government policy, 15, 68, 69 grants, 21, 97

218

Index

grassroots, 112 gravity, 106, 158 Greece, 208 greenhouse gas, ix, x, 1, 2, 3, 11, 12, 15, 16, 17, 19, 20, 25, 26, 28, 29, 30, 37, 38, 39, 40, 42, 48, 50, 55, 65, 75, 88, 104, 107, 111, 115, 132, 134, 140, 147, 183, 192, 195, 200 grids, 142 gross domestic product, 31 groundwater, 67 groups, 48, 68, 91, 144, 172, 186 growth, xi, 14, 37, 38, 42, 73, 77, 104, 112, 115, 120, 133, 142, 145, 201, 202, 207 growth rate, 202 guidance, 12, 68 guidelines, 50 Gulf Coast, 143

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H H2, 59, 62, 196, 199 handling, 58, 151, 158, 159, 161, 162, 198, 204 hands, 105, 131 hanging, 121, 131 harm, 37, 183, 189 hazardous wastes, 196 health, ix, 13, 37, 175, 182, 183, 189 health effects, 37 hearing, x, 33, 48, 69, 72, 74, 75, 77, 78, 79, 86, 121, 126, 143, 185 heat, ix, 6, 13, 41, 56, 57, 58, 61, 64, 92, 94, 95, 101, 109, 113, 117, 146, 148, 154, 155, 158, 159, 161, 162, 164, 165, 167, 168, 175, 178, 183, 184, 195, 196 heat transfer, 61, 64, 155, 158, 159, 161, 165 heating, 42, 55, 62, 95, 152, 158, 161 heavy metals, 37 hedging, x, 2, 28 high pressure, 189 high temperature, 49, 89, 91, 92, 94, 95, 196 higher quality, 137, 155 high-level, 24 high-risk, 12, 39 high-tech, 143 hiring, 93 Honda, 81 horizon, 76, 104, 121 host, 60, 97, 99, 177, 196 HTS, 203, 204, 205, 206, 208 human, ix, xi, 22, 103, 153, 156, 157, 163, 170, 182, 183, 185, 186 humorous, 51 Hungary, 208

hybrid, 51, 56, 58, 59, 73, 75, 134, 191 hydrocarbon, 105, 107, 147 hydrogen, 6, 7, 20, 31, 35, 41, 42, 43, 44, 57, 59, 62, 85, 94, 105, 128, 138, 145, 187, 196, 199 hydrogen gas, 94 hydrogen sulfide, 57, 62, 128, 145 I id, 22, 129, 142 Idaho, 81, 83, 108, 109 IEA, 151, 152, 185 Illinois, 91, 118, 173 implementation, 54, 76, 89, 114, 116, 121, 137, 150, 159, 184, 192 imports, xi, 39, 73, 91, 201, 203, 205, 206 impurities, 144, 145, 187, 198 in situ, 46 incentive, 11, 26, 44, 56, 70, 71, 99, 101, 127, 135, 141, 150, 191 incentives, 11, 16, 17, 19, 21, 24, 26, 40, 47, 50, 69, 71, 72, 88, 89, 97, 99, 101, 106, 116, 120, 121, 127, 131, 133, 135, 140, 141, 149, 151 inclusion, 110, 114 increased competition, 37 independence, 47, 48, 72, 73, 88, 93, 97 India, xi, 2, 28, 33, 34, 37, 84, 136, 186, 191, 201, 202, 203, 205, 206, 207 Indiana, 36, 45, 113, 197 indigenous, ix, 195 industrial, ix, 4, 5, 19, 21, 36, 46, 65, 68, 70, 83, 95, 96, 102, 103, 105, 106, 116, 123, 124, 130, 136, 147, 148, 158, 159, 182, 183, 185, 186, 187, 189, 192, 195, 196, 198, 203 industrial application, 4, 203 industrial wastes, 147 infancy, 58, 137 inflation, 20, 29 infrastructure, 15, 20, 36, 39, 44, 46, 48, 50, 71, 105, 106, 112, 116, 129, 136, 137, 140, 150, 152, 167, 199 injection, 21, 50, 64, 65, 67, 68, 72, 116, 138, 144, 145, 182, 189, 190, 193 innovation, ix, 1, 9, 15, 24, 25, 27, 30, 35, 103, 111, 200 Innovation, xi, 10, 29, 30, 31, 209 insight, 76 institutions, 114 instruments, 14, 21, 30, 164, 165, 167 insulation, 105 insurance, 3, 82, 139 insurance companies, 82

219

Index integration, x, 2, 23, 43, 56, 59, 62, 64, 85, 119, 133, 141, 146, 148, 154, 156, 171, 174, 176, 177, 178, 198 integrity, 67 intelligence, 156, 180 interaction, 145 interactions, 55, 67, 154, 176 interface, 163, 171 Intergovernmental Panel on Climate Change (IPCC), 186 International Energy Agency, 28, 54, 185 International Trade Administration, 206, 207, 209 Internet, 208 interstate, 67, 116 inventions, 96, 104 investment, x, 1, 11, 12, 16, 20, 21, 29, 35, 38, 39, 53, 54, 68, 83, 86, 87, 88, 89, 95, 96, 99, 101, 102, 104, 105, 106, 109, 114, 120, 123, 126, 127, 129, 138, 140, 141, 145, 151, 158, 186, 198 investment bank, 123 investors, 12, 30, 78, 97, 99, 103, 127, 129, 130 ion transport, 56 ionic, 45 IPCC, 186, 189, 190 Iran, 23 Ireland, 208 ITA, 206 Italy, 208 iteration, 60

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J Japan, 22, 69, 150, 151, 205 Japanese, 64 jobs, 106 joint ventures, 106 judgment, 13, 79, 122 jurisdiction, 68 justification, 20 K Katrina, 143 Kentucky, 34 kinks, 52 Kyoto Protocol, 104

landfills, 38 language, 156, 157 large-scale, x, 2, 3, 9, 19, 21, 23, 24, 41, 47, 49, 65, 67, 68, 69, 83, 86, 87, 97, 98, 99, 101, 108, 112, 116, 129, 143, 145, 182, 192, 193, 199 laser, 171 Latvia, 208 laws, 61, 111, 114, 187, 188 lawyers, 48, 183 leadership, 99, 101, 124, 135, 150, 186, 199 leakage, 49, 61, 67, 116, 137, 190 leaks, 190 learning, 54, 87, 90, 140, 150, 170, 191 legislation, x, 2, 3, 11, 12, 21, 25, 27, 28, 29, 31, 68, 96, 104, 117, 127, 131, 133, 134, 149, 151, 193 lenders, 123, 129 licenses, 203 licensing, 91 lien, 186 life cycle, 105, 147, 149 lifetime, 186 limitation, 13 limitations, 61, 78, 172 linear, 10 linkage, 25 links, 171 liquefaction, 23, 47, 48, 136 liquefied natural gas, 146 liquid fuels, 73, 148 liquids, 71, 72, 73, 105, 106, 107, 124, 136, 196, 204 Lithuania, 208 LNG, 152 loan guarantees, x, 1, 17, 19, 21, 24, 97 loans, 24, 106, 119 lobbyists, 188 location, 45, 63, 64, 85, 96 logistics, 121, 148 long distance, 92, 144 long period, 182, 190 long-distance, 67 long-term retention, 189 Los Angeles, 183 losses, x, 1, 9, 30, 56, 57, 64, 76, 113, 143, 144 love, 121 low-temperature, 57 Luxembourg, 208 M

L labor, 3, 20, 139, 143, 152 land, ix, 106, 182 landfill, 98, 100

machinery, 204 machines, 57, 156 macroeconomic, 132

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220

Index

maintenance, 5, 7, 9, 92, 94, 95, 139, 155, 158, 173, 174 Malta, 208 management, 38, 47, 48, 49, 50, 59, 60, 86, 88, 91, 93, 95, 102, 103, 132, 136, 150, 152, 155, 163, 170, 171, 172, 181 management practices, 132 mandates, 134 Manhattan, x, 2, 12, 21, 22, 23, 24, 31, 107 man-made, 72, 189 manpower, 116 manufacturer, 165, 197 manufacturing, 21, 53, 103, 120, 151, 196 mapping, 66 market, ix, x, xi, 1, 2, 3, 4, 6, 9, 11, 12, 13, 14, 15, 16, 19, 20, 23, 24, 25, 26, 31, 35, 37, 39, 42, 53, 54, 84, 88, 97, 104, 111, 120, 129, 130, 131, 132, 134, 135, 136, 140, 148, 151, 152, 162, 167, 179, 186, 188, 191, 196, 200, 201, 202, 203, 205, 206 marketplace, x, 16, 35, 40, 41, 47, 50, 51, 72, 73, 124, 153, 199 Maryland, 198 Massachusetts, 5, 10, 28, 86, 93 material resources, 170 maturation, 47, 49 maturation process, 47, 49 measurement, 18, 167, 198 measures, 114, 134, 146, 162, 182, 186, 191 media, 61 megawatt, 6, 51, 55, 77, 84, 86, 87, 89, 98, 99, 100, 115, 117, 119, 123, 128, 131, 149, 155, 167, 203 melts, 91, 94 membership, 46, 48 membranes, 4, 9, 45, 138, 198, 199 men, 96 mercury, xi, 34, 35, 37, 44, 45, 80, 87, 89, 92, 95, 97, 99, 100, 128, 154, 156, 162, 168, 169, 170, 171, 172, 177, 184, 196, 201 Mercury, 38, 40, 44, 49, 80, 154, 156, 168, 170, 178, 180 metals, 37, 92 methane, 38, 42, 49, 62, 92, 93, 94, 128 metric, 2, 12, 16, 20, 21, 29, 31, 41, 55, 59, 65, 66, 67, 143, 171, 185, 190 Mexico, xi, 22, 33, 75, 77, 201, 202, 203, 205, 206, 207 Middle East, 106, 125 military, 106 minerals, 145 mines, 71, 91 mining, 183, 184, 202

MIT, 5, 7, 8, 10, 12, 21, 26, 28, 29, 31, 32, 67, 68, 69, 87, 89, 90, 99, 101, 115, 132, 135, 138, 143, 152 Mitsubishi, 63 mixing, 64 modeling, 65, 165, 172, 197 models, 37, 50, 56, 65, 132, 165, 172, 175, 190 modules, 141, 156, 161, 167, 170, 173, 174, 175, 176, 178, 198 moisture, xi, 37, 56, 58, 113, 145, 153, 154, 155, 158, 159, 161, 162, 178, 199 moisture content, 58, 113, 158, 159, 161, 178 momentum, 54 money, 72, 80, 81, 82, 83, 85, 119, 123, 124, 125, 131, 135, 191 Montana, 56, 85, 91, 92, 117, 119 moratorium, 152 Morgan Stanley, 11, 29 morning, 33, 46, 48, 77, 97, 99 motivation, 11 motors, 61 mountains, 183 mouth, 92, 161 movement, 46, 106 MSW, 147 municipal sewage, 147 municipal solid waste, 105, 147 N NASA, 22, 24, 31 nation, ix, 22, 48, 52, 75, 78, 102, 133, 145, 158, 159 National Aeronautics and Space Administration, 31 National Income and Product Accounts, 31 national policy, 93, 186 National Research Council, 35 National Science Foundation, 39 national security, 36, 145, 195 Native American, 48 Native Americans, 48 natural gas, ix, 11, 21, 31, 34, 37, 38, 56, 65, 73, 77, 79, 90, 91, 92, 93, 94, 95, 96, 97, 98, 100, 102, 103, 106, 109, 110, 111, 112, 114, 116, 118, 128, 129, 130, 131, 132, 134, 142, 143, 146, 149, 152, 183, 187, 189, 191, 195, 196, 197 natural resources, 74, 150, 151 negotiation, 159 Netherlands, 199, 208 network, 94, 154, 155, 156, 162, 163, 164, 165, 166, 167, 168, 169, 170, 171, 172, 175, 178, 181 neurons, 156 New Mexico, 22, 33, 75, 77 New World, 24, 31

221

Index New Zealand, xi, 201, 202, 203, 206, 207 next generation, 36, 39, 45, 66 nickel, 60 nitrogen, xi, 4, 34, 37, 44, 50, 64, 91, 94, 95, 97, 99, 154, 156, 184, 196, 197, 201 nitrogen compounds, 37 nitrogen oxides, 4, 34, 97, 99, 154, 156, 184, 196 nitrous oxide, 38, 78 non-profit, 53 normal, 39, 80, 92, 141, 151, 186, 187, 188 North America, 31, 34, 36, 91, 93, 96, 97, 112, 195, 197 North Carolina, 34, 53, 85 Norway, 65, 66 nuclear, 23, 37, 38, 73, 77, 84, 85, 88, 110, 112, 114, 133, 134, 143, 146, 183 nuclear power, 77, 84, 146, 183

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O obligation, 31, 117, 191, 192 obligations, 193 OECD, 202 offshore, 167 Ohio, 45, 60, 86, 88, 97, 98, 99, 100 oil, 15, 21, 22, 23, 24, 25, 31, 37, 38, 39, 49, 58, 60, 65, 66, 67, 71, 73, 78, 79, 80, 81, 87, 88, 91, 92, 93, 95, 98, 100, 102, 103, 105, 106, 107, 109, 115, 121, 130, 131, 132, 137, 145, 146, 149, 183, 187, 189, 193, 195 oil recovery, 15, 49, 65, 71, 81, 87, 88, 92, 95, 98, 100, 105, 107, 109, 115, 121, 132, 137, 145, 188, 189, 193 Oklahoma, 65 old-fashioned, 185 online, 94, 129, 164, 165, 167, 170, 171, 172, 173, 175, 183 on-line, 53, 57, 134, 142 opacity, 156, 163, 166, 175 operator, 157, 165, 167, 170, 178, 188 Operators, 199 OPM, 165, 181 opposition, 184 optimal performance, 154 optimization, 61, 154, 155, 156, 157, 163, 165, 167, 168, 169, 170, 171, 173, 174, 175, 176, 177, 178 Oregon, 108, 109, 132 organic, 118 Organization for Economic Cooperation and Development, 202 oversight, 65, 189 ownership, 49, 137 oxidation, 5, 170

oxide, xi, 38, 44, 58, 78, 138, 162, 201 oxygen, 5, 6, 7, 29, 55, 56, 57, 59, 64, 88, 91, 92, 94, 105, 136, 138, 187, 188, 196 P Pacific, 110, 135 packaging, 103, 105 paints, 103 particles, 58, 97, 99, 158, 170 particulate matter, xi, 100, 154, 162, 163, 172, 201 partnership, 40, 51, 82, 83, 85, 96, 102, 103, 106, 119, 123, 126, 135, 138, 148, 198 partnerships, 17, 30, 36, 47, 51, 78, 79, 83, 85, 109, 114, 119, 135, 138 patents, 97, 99 pathways, 14, 44, 52, 138, 197 payback period, 106 penalties, 62, 63, 141, 142, 144, 187, 188 penalty, 28, 58, 64, 129, 143, 144, 192 Pennsylvania, 31, 56 perception, 105 periodic, 16, 27, 164 permeability, 45, 144 permit, 3, 16, 138, 176 perseverance, 54 personnel costs, 139 petrochemical, 106 petroleum, 31, 56, 75, 90, 92, 96, 105, 106, 138, 188, 195, 196 petroleum products, 75 pharmaceuticals, 103 physics, 61 pilot studies, 188 pipelines, 3, 5, 15, 50, 67, 94, 116, 144, 187, 189 planning, 29, 111, 122, 132, 136, 151 plastics, 102, 103, 105, 106, 119, 120, 124, 148 plug-in, 73, 74, 75, 77 poison, 184 Poland, 208 policy choice, 39 policy initiative, x, 2, 21 policymakers, 22, 114 pollutants, 5, 6, 7, 13, 34, 37, 38, 43, 51, 55, 64, 95, 98, 128, 155, 167, 184 pollution, 13, 36, 60, 75, 119, 146, 184, 186, 188 polymers, 45 population, 92, 94 pores, 144 porosity, 145 porous, 65, 128 portfolio, 35, 38, 40, 42, 47, 48, 52, 53, 55, 88, 112, 134, 143, 146, 149, 196

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222

Index

portfolios, 73 Portugal, 208 potential energy, 40 96, 197, 198, 201, 202, 203, 204, 205, 207, 208 power generation, 2, 19, 39, 42, 44, 53, 58, 62, 83, 84, 87, 89, 95, 109, 110, 113, 117, 128, 131, 141, 148, 154, 174, 177, 187, 196, 203 power stations, 39 pragmatic, 54 predictability, 25 prediction, 119, 165 preference, 136 premium, 62, 141, 196 present value, 29, 53 president, 109 President Bush, 20, 38 press, 31, 73, 80, 180 pressure, 5, 6, 29, 46, 57, 58, 59, 61, 62, 63, 64, 70, 89, 92, 112, 113, 144, 155, 187, 189, 196, 199 prevention, 30, 61 price floor, 16, 97, 130, 131 price index, 16, 31 price mechanism, ix, 1, 9, 11 price signals, 21, 26 price stability, 130 prices, 11, 16, 23, 24, 25, 26, 27, 35, 36, 37, 39, 52, 62, 73, 84, 93, 102, 106, 108, 110, 112, 115, 130, 131, 132, 133, 134, 140, 142, 143, 146, 149, 182, 192, 195, 197 pristine, 14 private, x, 2, 9, 19, 20, 21, 22, 23, 39, 40, 44, 47, 48, 51, 54, 78, 83, 85, 97, 99, 102, 103, 106, 109, 114, 116, 119, 129, 130, 134, 135, 140, 144, 145, 152, 191, 199, 200 private sector, 9, 19, 22, 39, 44, 83, 97, 116, 130, 191, 199, 200 probability, 83, 99, 101 problem-solving, 157 producers, 48, 54, 62, 124, 131, 132 production, xi, 11, 20, 21, 24, 31, 35, 36, 38, 39, 42, 44, 47, 48, 54, 59, 60, 65, 66, 83, 91, 94, 95, 97, 102, 103, 106, 109, 112, 114, 115, 118, 126, 129, 130, 131, 136, 141, 148, 151, 172, 177, 179, 183, 187, 192, 196, 197, 198, 199, 201, 205, 207 production costs, 11, 130, 131, 192 production targets, 24 productivity, 79 profit, 11, 53, 129 profitability, 130, 200 profits, 138 pronunciation, 97 proposition, 79, 143 prosperity, 34, 36, 195

protection, 130, 182, 185, 192, 193 protocols, 163 prototype, 24, 155, 159, 161, 162, 198 prudence, 114 PSD, 13 public, ix, 3, 9, 13, 38, 39, 40, 44, 47, 50, 51, 62, 68, 78, 82, 85, 89, 97, 102, 104, 106, 108, 109, 110, 111, 114, 117, 119, 130, 134, 135, 138, 140, 141, 144, 145, 147, 183, 189, 199 public sector, 38, 140, 144, 145 public-private partnerships, 51, 78 pumping, 63 pumps, 6, 99, 101, 165, 198 purchasing power, 192 purification, 7 Q quality of life, 75 R R&D, x, 1, 9, 10, 15, 17, 20, 21, 23, 24, 25, 29, 30, 31, 35, 36, 38, 39, 40, 41, 42, 45, 46, 52, 53, 60, 66, 76, 82, 88, 89, 90, 109, 135, 136, 137, 152, 195, 197 radiation, 158 rain, 16, 37 range, 4, 9, 21, 39, 42, 54, 56, 79, 103, 105, 106, 112, 132, 157, 163, 165, 175, 185, 199 raw material, 43, 103, 104, 105, 170 Reagan Administration, 23, 24 reagent, 155 reagents, 5, 7, 9 reality, 83, 102, 148, 154, 192 reclamation, 184 recognition, 54, 85, 93 reconcile, 73, 74, 75, 182, 192 recovery, 15, 31, 49, 57, 60, 61, 63, 65, 71, 81, 87, 88, 92, 95, 98, 100, 105, 107, 108, 109, 110, 115, 121, 132, 137, 138, 141, 145, 146, 148, 188, 189, 193 recovery processes, 115 refineries, 13, 91, 93 refining, 196 reflection, 55 reforms, 184 refractory, 198 regenerate, 64 regeneration, 62, 63, 64 regional, 17, 30, 36, 47, 68, 79, 82, 83, 85, 121, 142 regulation, x, 1, 11, 13, 14, 25, 26, 39, 61, 83, 140

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Index regulations, 11, 12, 15, 16, 21, 30, 40, 52, 76, 90, 133, 137, 139, 140, 141, 142, 189, 193 regulators, x, 1, 11, 54, 83, 108, 110, 111, 114, 115, 119, 126, 134 regulatory bodies, 146 regulatory framework, 3, 68, 73, 80, 116 regulatory requirements, 140 relationship, 67 relationships, 156, 157 relevance, 21 reliability, 29, 52, 54, 56, 59, 70, 91, 92, 94, 112, 141, 145, 155, 158, 173, 175, 177, 198 remediation, 50, 67, 189 remediation procedures, 67 renewable energy, 37, 38, 111, 114, 134, 182, 183 renewable resource, 134 research and development, x, 1, 2, 4, 9, 10, 15, 17, 28, 30, 93, 96, 115, 116, 134, 151, 161, 188, 191 Research and Development, 22, 36, 116, 195, 199 reserves, 72, 79, 91, 93, 158, 198 reservoirs, 47, 49, 52, 65, 67, 83, 190 residential, 196 residues, 44 resistance, 77, 146, 167 resolution, 35, 37, 46, 53, 176, 198 resources, ix, 11, 36, 37, 38, 40, 66, 72, 73, 74, 75, 78, 91, 99, 101, 104, 108, 110, 111, 112, 113, 114, 125, 132, 134, 136, 139, 146, 150, 151, 170, 174, 176, 178, 182, 185, 189, 193, 195, 202 respiratory, 38 responsibilities, 111 restructuring, 19, 20 retail, 21, 31, 182, 192 retention, 189 revenue, 30, 96 rewards, 108, 111, 186 risk, x, 2, 11, 12, 28, 39, 50, 61, 67, 68, 80, 83, 87, 88, 90, 91, 99, 101, 102, 105, 109, 110, 111, 114, 116, 119, 123, 127, 135, 139, 140, 141, 148, 150, 168, 172 risk sharing, 141 river systems, 112 rivers, 200 roadmap, 32 RTI, 58 runaway, 189 S safety, 26, 122, 134, 189 sales, 35, 36, 45, 96, 103, 131, 191, 192, 203 saline, 6, 47, 49, 65, 67, 144, 190 savings, 62, 98, 100, 130, 137

223

scalable, 59 scaling, 59, 93 scheduling, 77 search, 102, 106, 157, 175 Secretary of Defense, 125 Secretary of the Treasury, 19 security, 35, 36, 37, 38, 39, 43, 44, 47, 48, 73, 74, 75, 78, 90, 93, 102, 103, 104, 106, 121, 145, 152, 195, 197 selecting, 93 selectivity, 45 semiconductor, 124 Senate, x, xi, 33, 82, 86, 99, 101, 106, 112, 117, 121, 123, 127, 131, 133, 149, 151, 209 sensing, 163 sensitivity, 132 sensors, 42, 154, 155, 156, 165, 167, 169, 170, 171, 172, 174, 178, 197 separation, 7, 8, 43, 59, 63, 80, 94, 95, 138, 150, 186, 188, 198, 199 series, x, 103, 138, 153, 164, 172 services, 61, 103, 139, 140, 176, 186 sewage, 147 shape, 20 shaping, 9 shareholders, 108 sharing, 50, 72, 138, 141, 193 Shell, 91 short-term, 15, 22, 87, 127, 131, 133, 134, 149, 151, 193 Siemens, 91, 98, 100 signals, 12, 21, 25, 26 silver, 54, 85 simulation, 170, 172 simulations, 175 sites, 15, 36, 45, 46, 48, 50, 60, 65, 67, 68, 93, 96, 102, 113, 116, 135, 182, 190 skills, 148 slag, 91, 94, 95, 128, 164, 165, 167 Slovakia, 208 sludge, 147 SO2, 4, 5, 6, 7, 10, 13, 14, 15, 16, 17, 26, 30, 58, 63, 80, 89, 99, 100, 127, 140, 145, 154, 162, 170, 172, 178, 181 socially responsible, 150 software, xi, 153, 154, 155, 156, 157, 163, 165, 167, 170, 171, 174, 175, 176, 177, 179 soil, 184 solar, 22, 74, 77, 88, 104, 112, 193 solid waste, 38, 105, 147, 196 solvent, 4, 5, 6, 45, 57, 59, 60, 62, 63, 64, 141 solvents, 9, 62, 63, 187 soot, 162, 164, 175, 204

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224

Index

sorbents, 9, 64 sounds, 118, 129, 150 South Africa, xi, 105, 201, 203, 205, 206, 207 South Korea, xi, 201, 202, 203, 205, 206, 207 Southeast Asia, 136 soybeans, 104 Soyuz, 31 Spain, 208 speciation, 154, 168, 169, 170, 171, 172 species, 58, 62, 63, 112, 156, 169, 170, 171 specific heat, 159 spectrum, 46, 47, 48, 49, 82, 83 speed, 61, 97, 129, 182, 186 sponsor, 178 spot market, 130 stability, 16, 25, 26, 61, 130 stabilization, 38, 130 stages, 16, 24, 36, 46, 47, 49, 69, 129, 182, 188 stakeholder, 68 stakeholders, 68, 69, 107, 144 standards, x, 12, 13, 26, 50, 112, 116, 120, 131, 132, 149, 153, 182, 188, 198, 200 state regulators, 110, 111 statistics, 28, 119 statutes, 110 statutory, 192 steel, 66, 84 stimulus, 191 stock, 30, 77, 119, 120 strain, 149 strategies, 91, 110, 142, 147, 176 streams, 5, 105, 107, 115, 183, 184, 199 strength, 103 strikes, 124 students, 80 subsidies, 15, 186, 187 sugar, 104 sugar cane, 104 sulfate, 5 Sulfide, 57 sulfur, xi, 4, 14, 16, 34, 37, 45, 50, 57, 58, 62, 80, 82, 92, 95, 97, 99, 128, 144, 145, 154, 157, 184, 191, 196, 198, 201 sulfur dioxide, xi, 4, 34, 50, 80, 97, 99, 128, 145, 154, 184, 191, 201 supercritical, 28, 29, 47, 49, 50, 55, 57, 59, 60, 62, 63, 64, 67, 69, 70, 75, 88, 89, 108, 113, 114, 116, 138, 139, 140, 143, 151, 203, 204 suppliers, 60, 144, 168 supply, ix, 2, 12, 16, 27, 35, 36, 37, 38, 54, 72, 77, 79, 84, 104, 105, 106, 107, 109, 112, 134, 149, 155, 178, 195, 202 supply chain, 105, 107

support services, 61 sustainability, 104 Sweden, 208 switching, 136, 157 synthesis, 31, 43, 55, 56, 57, 59, 62, 63, 94, 105, 182, 196, 197, 198, 199 synthetic fuels, 23, 24, 31 T targets, 12, 16, 24, 41, 42, 104, 127, 131, 133, 134, 139, 149, 152, 199 tax credit, x, 1, 17, 19, 21, 60, 97, 99, 101, 106, 109, 112, 114, 126, 129, 134, 140 tax credits, x, 1, 17, 19, 21, 60, 106, 109, 114, 126, 140 technicians, 40 technological advancement, 3 technological progress, 27, 146 temperature, 5, 7, 42, 57, 59, 60, 61, 62, 64, 89, 92, 94, 151, 158, 159, 161, 162, 166, 198 Tennessee, 70, 121, 197 test data, 156 testimony, xi, 34, 35, 36, 47, 48, 53, 69, 76, 78, 90, 92, 93, 96, 102, 121, 123, 126, 127, 129, 131, 133, 134, 138, 143, 145, 149, 151, 194, 195 Texas, 6, 46, 56, 65, 82, 92, 154, 166, 168, 169, 170, 172 Thailand, 205 The Economist, 84 thermal efficiency, 55, 58, 62, 154, 177, 198, 199 thermodynamic, 54, 55, 58, 59, 175 timetable, 111, 119 timing, 3, 9, 10, 26, 34, 87, 90, 121, 127, 140 title, 19, 50 top management, 93 toxic, 184 trace elements, 37, 45 tracers, 46 tracking, 176 trade, 12, 13, 15, 16, 26, 27, 29, 30, 121, 122, 127, 131, 133, 134, 149, 151, 191, 192, 203, 205, 207 trading, 16, 192 training, 156, 165, 172 trajectory, 17 transfer, 57, 61, 64, 155, 158, 159, 161, 164, 165 transformation, 134 transition, 30, 44, 107 transmission, 71, 110, 112, 133, 192 transparent, 26, 170 transport, 3, 5, 7, 8, 15, 26, 50, 56, 58, 59, 79, 94, 116, 138, 184, 198

225

Index transportation, ix, 2, 3, 5, 7, 19, 28, 43, 47, 49, 50, 57, 62, 63, 64, 67, 73, 74, 75, 105, 106, 135, 137, 143, 144, 195, 196, 198, 199 transportation infrastructure, 137 travel, 71 Treasury, 19, 197 Turkey, 31 turnover, 24 U U.S. economy, 53, 143, 146 U.S. Geological Survey, 192 uncertainty, 20, 29, 39, 52, 56, 82, 111, 140, 144 uniform, 50 United Kingdom, 132, 208 universe, 112 universities, 79 urea, 141, 197 Utah, 65, 108, 109, 110

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V vacuum, 10, 19, 125 validation, 61, 67, 138, 150, 172 validity, 168 values, 57, 143, 144 vapor, 7, 59, 64, 169, 170 variables, 3, 9, 131, 156, 171, 172, 173, 175 variation, 127 vegetation, 183 vehicles, 73, 75 venture capital, 91, 93, 122, 127 vision, 60, 118, 119 visualization, 42 volatility, 16, 26, 27, 130, 133, 149, 191 vulnerability, 54 W Wall Street Journal, 72 war, 23

warrants, 58 Washington Post, 30 waste products, 184 waste water, 98 wastes, 105, 196 wastewater treatment, 100 water, ix, 5, 7, 29, 38, 44, 46, 55, 56, 57, 58, 59, 61, 62, 64, 67, 71, 75, 83, 98, 100, 103, 105, 118, 154, 155, 156, 159, 161, 162, 164, 167, 172, 182, 184, 196 water evaporation, 56 water quality, 44 water resources, 75 water vapor, 7, 64 water-soluble, 162 wear, 154, 198 web, 24, 31, 137, 152 welfare, 13 well-being, 183 wells, 65, 71, 79, 95, 116 wholesale, 52, 133, 142, 146 wind, 37, 74, 77, 88, 110, 112, 114, 126, 129, 133, 193 wisdom, 127 witnesses, 78, 127, 129 women, 96 wood, 105, 199 workstation, 157 World War, 186 Wyoming, 56, 71, 72, 74, 82, 83, 91, 92, 108, 109, 114, 117, 119, 126, 187 Y yield, 85, 94, 97, 155, 174 Z zinc, 58, 198 zinc oxide, 58