“NowGen”: Getting Real about Coal Carbon Capture and Sequestration

Armond Cohen is Co-Founder and Executive Director of the Clean Air Task Force (CATF), a U.S. nonprofit organization founded in 1996 and dedicated to reducing the human impact on the Earth’s atmosphere and the systems that depend on it. He is a member of the Keystone Energy Board and the Environmental Protection Agency’s Clean Air Act Advisory Committee. Mike Fowler is Technology Coordinator for the Coal Transition Project at the CATF, where he provides technical and regulatory guidance for energy technology innovation efforts. Prior to joining CATF he was New Source Review Supervisor and Enforcement Manager in the Air Quality Bureau of the New Mexico Environment Department. He began his career as a Project Scientist in the Division of Applied Sciences at Harvard University. Kurt Waltzer is Carbon Storage Development Coordinator for the CATF’s Coal Transition Project. His work is focused on policy, project facilitation, and business-to-business efforts related to CCS development. Prior to CATF he worked for the Izaak Walton League of America coordinating the Midwest Power Plant Campaign and developed the Ohio Environmental Council’s clean air program, where he led the effort to create the state’s $100 million energy efficiency loan program and net metering policy.

‘‘NowGen’’: Getting Real about Coal Carbon Capture and Sequestration It’s clear that managing climate change will require addressing one of its key drivers: coal-fired electricity generation. This likely can’t be done by just avoiding coal use altogether. We need cost-effective CCS and enabling technologies, we need them at commercial scale, and we need them soon. Armond Cohen, Mike Fowler and Kurt Waltzer

I. Introduction The world faces a stark challenge on climate change. Recent scientific evidence suggests we need to effectively zero out energy-system carbon dioxide (CO2) emissions by midcentury to avoid the most extreme warming scenarios. At the same time, coal is likely to remain a significant energy source, especially given continued growth in world demand for electricity. Confronted with these realities, nearly every major assessment concludes that carbon

capture and sequestration (CCS) technology to de-carbonize fossilfuel systems, especially coal electricity, is essential. espite a decade of increasingly urgent calls for rapid deployment of CCS, a wide and dangerous gap remains between rhetoric and reality. We still have only a few small-scale demonstrations of geologic carbon storage—and none are connected to actual coal power plants. Worldwide, only two projects are under construction with strong prospects of implementing commercial-scale

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CCS: Duke Energy’s Edwardsport IGCC plant in Indiana and the GreenGen IGCC plant in China. his will not do. Progress toward a viable ‘‘CCS industry’’ needs to accelerate dramatically. This article argues for a concerted effort to build 20 GW of CCS in the U.S. and equivalent amounts in other OECD countries by 2020. This means we must:  Widely deploy ‘‘NowGens’’ in addition to building the recently revived FutureGen project at Matoon, Ill. NowGen projects would utilize intermediate transition technologies that are available today, such as integrated gasification combinedcycle (IGCC) systems with partial CCS and substitute natural gas produced from coal with CCS.  Create incentives for a pipeline infrastructure to move captured CO2 from plants to geologic sequestration sites. In addition, we must:  Support further R&D on advanced CCS and enabling technologies—including postcombustion capture options that could address the substantial base of existing coal capacity.  Establish CO2 performance standards for coal plants as CCS technology phases in.  Develop needed regulations for geologic carbon sequestration.  Pursue R&D to ensure the wide-scale availability of deep saline formation sequestration by 2020.

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 Develop ‘‘rules of the road’’ for future geologic sequestration projects in terms of property rights and long-term site management and liability. his is a tall order. But major global industries— including the oil and gas industry—have developed on this scale and at this pace before. It can be done. And if we are at all serious about addressing climate change, it must be done.

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A concerted effort is needed to build 20 GW of CCS in the U.S. and equivalent amounts in other OECD countries by 2020.

II. CCS is Critical to a Zero-Carbon World The title of a recent article by two leading climate researchers sums up the message emerging from the latest scientific evidence: ‘‘Stabilizing climate requires near-zero emissions.’’1 Even the most dramatic, 50–80 percent CO2 reduction goals generally being discussed likely are not enough. We need a near-100-percent reduction by mid-century at the latest. Energy systems need to change faster.2 Part of the urgency stems from the reality that warming impacts from today’s emissions may last

as long as 1,000 years3; we cannot assume that reducing emissions ‘‘tomorrow’’ means we can reverse damage done to date. Worse, we risk passing irreversible ‘‘tipping points’’ that trigger abrupt and catastrophic changes, such as major ice melt in the polar regions, extensive rainforest loss, and radical alterations of critical weather and ocean circulation patterns. Such tipping points could be in sight if current emission trends continue for another decade or more.4 Unfortunately, we are moving in the wrong direction fast. In recent years, China has added coal capacity at a rate of one large new plant per week (70–100 GW per year)5 and India – potentially the world’s most populous country by 2030 – could ramp up as well. The International Energy Agency (IEA) currently projects that world coal capacity will nearly double by 2030, an increase of 1,310 GW.6 If this build-out occurs without CCS, it will increase world CO2 emissions by about 12.6 billion metric tons annually7—roughly twice current U.S. emissions from all sources. Clearly, China, India, and other developing countries will ‘‘make or break’’ any global effort to cut CO2 emissions—in fact, changes in their emissions trajectory will overwhelm any plausible reductions by developed countries. Numerous studies—including studies by the IEA, the Intergovernmental Panel on Climate Change, the U.S. Climate

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Change Science Program (CCSP), and several major environmental organizations—have assessed the relative roles that different technologies might play in meeting various climate stabilization targets. This body of work (and more) suggests that CCS has economic advantages relative to other options and is likely to be indispensable in achieving a zero-carbon energy mix. Specifically, these studies (which are reviewed and summarized at the CATF Web site, http://www.catf.us/ projects/power_sector/ advanced_coal/) find the following:  Stabilizing atmospheric CO2 at 450 parts per million by volume (ppmv) could require more than 250 GW of fossil power with CCS globally by 2030 (U.S. CCSP, 2007)8;  Fossil fuels with CCS might need to provide 26 percent of global energy supply under stabilization constraints (WWF, 2007)9;  Combined power sector and industrial CCS could provide the largest single CO2 abatement option in the U.S. in 2030 (McKinsey & Co., 2007)10;  Costs for stabilizing CO2 with widespread CCS deployment could be reduced 30 percent or more compared to the costs without CCS (IPCC, 2005)11;  CCS is likely to play a role roughly equivalent to that of energy efficiency and renewables in climate mitigation (IPCC, 2007).12

Figure 1: Global Electricity Consumption in 2004: Population vs. per Capita Consumption (Source: CATF, from U.S. DOE International Energy Outlook, 2005)

A. A demanding challenge Figure 1 illustrates the magnitude of the global energy challenge. Each rectangle is drawn with height proportional to average per capita electricity consumption and width proportional to population.13 The area of each rectangle represents total consumption in 2004. Shades are used to indicate what fraction of electricity comes from coal (middle is between one-third and two-thirds, light is less than onethird, and dark is more than twothirds). Clearly, if a reasonable target were set for per capita electricity consumption, even large reductions in the developed world—say 30 percent—would not offset enormous demand growth in the developing world. Massive capacity additions would still be needed. Continued population growth in developing countries, along with urbanization, industrialization, and income growth on a mass scale will only add to these pressures. s already noted, rapid growth is well underway in developing countries, with China

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adding more coal-fired capacity in 2006 and 2007 than exists in Western Europe today and India planning 92 GW of new capacity (most of it thermal power) in the next five years.14 The current global economic downturn may moderate these trends, but only temporarily. B. Other zero-carbon energy options: Not betting the farm While it would be convenient if a combination of efficiency, truly ‘‘clean’’ renewable, and other zerocarbon sources15 could suffice to meet all the world’s energy needs, common sense casts serious doubt on this proposition.16 First, there will be limits to how far we can reduce consumption with energyefficiency policies. Policy efforts in the state of California have reduced per capita electricity demand by roughly 10 percent relative to the U.S. average,17 yet each Californian still uses about 7,000 kWh of electricity per year, more than almost anyplace in the world outside North America (and nearly five times the level of the average Chinese). Moreover, California’s overall demand is still

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growing. Meanwhile, other lowcarbon supply options confront their own formidable deployment challenges. For example, intermittency, lack of longdistance transmission capacity to remote sites, and land-use requirements remain hurdles to a massive scale-up of renewable sources like wind and solar power, despite continued technology improvements. The scale-up challenge is truly daunting: displacing just 1 Gt of annual CO2 emissions (out of the 7 Gt needed just to flatten global emissions by mid-century) would require 2,000 GW of wind energy—twice the current U.S. base of all installed electrical capacity. Alternatively, it would require a three-fold expansion of current world nuclear capacity.18 Meanwhile, movement toward an electrified vehicle fleet, in the U.S. and worldwide, may be desirable on climate and energy security grounds, but it will also contribute to growing electricity demand. Given remaining cost and technology challenges and ongoing concerns about indirect land-use impacts, we cannot count on biofuels to provide truly carbonneutral solutions for the vehicle sector within the next few decades.19 If electricity therefore has to play a larger role, decarbonizing fossil-based power production becomes that much more urgent. bviously it is extremely difficult to forecast the deployment trajectory of different technologies decades into the future. But it would be unwise to ‘‘bet the farm’’ that fossil fuels in

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general, and coal in particular, do not have a significant role to play for some time to come. C. History suggests that rapid scale-up to a gigatonne-scale CCS industry is well within our capabilities For a typical 500 MW coalfueled power plant, CCS involves

separating, transporting, and storing about 4 million tonnes of CO2 each year.20 Compressed to a dense, supercritical state this mass of CO2 would occupy a space roughly 500 meters on each side and 33 meters thick.21 Applying the same technology at hundreds of plants represents the central challenge of CCS: the existing fleet of coal plants in the U.S.—at 320 GW combined capacity— produces more than 2 Gt of CO2 each year. ortunately, analogues from other industries suggest that this sort of scale-up is feasible over the next two decades. In a single 20-year period between 1950 and 1970, for example,

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installed electric-generating capacity in the U.S. more than quadrupled, from 69 GW to 316 GW. This matches the scale of the global CCS build-out that some studies suggest is necessary by 2030 to meet some climate targets. And it is significantly less capacity than China is expected to add over the same time period.22 Similarly, approximately 150,000 miles of natural gas pipeline were built in the U.S. between 1960 and 1980.23 The CO2 pipeline network needed to support several hundred GW of CCS-equipped power plants could be much smaller, perhaps less than 30,000 miles in some scenarios.24 Assuming 35 CO2 injection wells per GW implies roughly 10,000 wells would be needed for sequestration in this scenario—a large number, but well below the number of oilfield brine injection wells currently operating in the U.S. (150,00025) and equivalent to just six months of natural gas drilling activity in the Alberta Basin (20,000 wells per year26). Figure 2 compares the CCS infrastructure ‘‘lift’’ to comparable energy-system scale-ups in the past.27 In sum, experience suggests that large-scale CCS can be achieved over the next several decades. It also suggests that an entirely new, specialized industry with CO2 as its central, fungible commodity will need to emerge. Similar to the major energy industries that came before, this evolution may occur from the

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Figure 2: Scale-up Rates of Major Energy Technology Infrastructure over 20-Year Periods (compiled by CATF from various sources)

bottom up—as capture systems at individual plants combine to form regional systems with multiple CO2 sources, pipeline networks, and sequestration sites. Moreover, this new industry may need to be organized and governed as a regulated system in its own right.

III. CCS Technologies: Ready for Prime Time, but Scale-Up Needed CCS systems encompass a suite of technologies, including chemical and physical solvents to absorb CO2 from exhaust or fuel gas; technologies for compressing CO2 and transporting it through pipelines; technologies for characterizing, operating, and monitoring geological sequestration sites; gasification and related technologies for producing hydrogen-rich gaseous

fuel or substitute natural gas; and technologies associated with CO2flood enhanced oil recovery. Most of the component technologies needed to implement CCS at the scale of individual power plants are already in commercial service in the U.S. Properly integrated, they can be applied on a much larger scale. he next few sections review the primary technology pathways for CCS, including options for pre- and postcombustion capture, as well as oxy-combustion, underground coal gasification, and geologic carbon sequestration.

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A. Coal gasification: The leading technology for full CO2 capture Removing CO2 from the synthesis gas (syngas) produced by coal gasification prior to combustion, where it is

concentrated and under high pressure, is thermodynamically advantageous compared to separating CO2 from the exhaust of pulverized coal plants after combustion.28 In IGCC plants, syngas may be chemically converted to a mixture composed primarily of hydrogen and CO2. The CO2 can then be removed using conventional acid gas removal technologies developed by the petrochemical industry, leaving a hydrogen-rich syngas that can be burned in a highly efficient combined-cycle power plant. IGCC systems with integrated CO2 capture are available from a growing number of vendors, including Mitsubishi Heavy Industries (MHI), GE, Siemens, ConocoPhillips, and Shell. These systems present larger process integration challenges, especially if equipped with high levels of CO2 capture, than substitute natural gas (SNG) systems (see below), but are expected to be more efficient if electricity production is the ultimate goal. While no IGCC plants currently operate with CCS, Duke Energy plans to implement some level of capture at its new Edwardsport IGCC plant, provided regulators approve the additional expense. There are also plans to phase in capture at a new IGCC project under construction in China.29 Other commercial-scale projects are currently under development in California, Texas, Alberta, and Australia.30 Unfortunately, capital-cost increases since 2006 have caused other projects to be

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canceled or postponed, raising the question whether more costcompetitive technologies are needed to implement further commercial-scale demonstrations in the early years. B. SNG: A promising platform for early CCS? One potential transition technology involves gasifying coal to produce substitute natural gas (SNG; mostly methane), with a byproduct stream of captureready CO2 that contains half or more of the carbon originally in the coal.31 Assuming this byproduct CO2 is captured and stored while the SNG is utilized in a natural gas combined-cycle (NGCC) plant, overall CO2 emissions are on par with those for conventional gas-based generation. Furthermore, recent estimates suggest that SNG production can be costcompetitive with conventional natural gas in some scenarios, making it a potentially attractive bridge technology.32 ll the technologies needed for SNG have been successfully employed together at the Dakota Gasification Company facility in Beulah, N.D., which daily converts roughly 18,500 tons of lignite into 150 million standard cubic feet (scf) of SNG33—enough to fuel 780 MW of electric capacity.34 As of 2004, this facility was capturing approximately 95 million scf of CO2 per day (more than 1 million tonnes per year), which was being transported by high-pressure

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pipeline 205 miles north to be used for enhanced oil recovery at the Weyburn oil field in Saskatchewan. By July 2008 approximately 11.4 million tonnes of CO2 had been captured and stored in this way.35 The equipment needed for commercial SNG production is available from multiple vendors and more than a dozen

than separation from syngas, the efficiency losses associated with post-combustion capture on a pulverized coal plant are substantially higher than the efficiency losses for precombustion capture on an IGCC plant (a relative decrease of roughly 31 percent for PCC, versus 18 percent for IGCC), even though modern versions of both plants could achieve roughly similar levels of efficiency when operated without CO2 capture.37 he largest currently operating post-combustion capture system on a coal boiler is in Trona, Calif., where a Kerr-McGee (now ABB Lummus) amine system built in 1978 captures 900 tons of CO2 per day (tpd).38 This is roughly equivalent to the CO2 emissions from a 35 MW coal power plant. The CO2 is used in the production of soda ash. Several additional amine-based systems are also in operation, including two that produce food-grade CO2 at coal plants in the U.S., two in Japan, and several at large industrial facilities that manufacture urea. MHI plans to install a 100 tpd post-combustion capture system on a coal-fired plant in Germany in 201039 and could have a commercial-scale system in operation as soon as 2015.40 Fluor Corporation has experience with post-combustion capture on natural gas power plants, and claims to be ready to provide a commercial-scale system.41 HTC PureEnergy and Cansolv are also developing amine-based post-combustion capture systems. Processes based

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plants have been proposed in the U.S.36 C. Post-combustion capture: Big hurdles but potentially big payoffs for existing plants Post-combustion or ‘‘end-ofpipe’’ CO2 capture technology has the advantage that it could potentially be retrofit to existing coal plants. The central process involves bringing flue gas into contact with a regenerable solvent—typically an aminebased solution—which absorbs CO2 from the gas. The solvent is then heated, driving off relatively pure, concentrated CO2. Because these processes must overcome greater thermodynamic hurdles

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on chilled and aqueous ammonia are under development by Alstom and PowerSpan, respectively, and these may offer efficiency improvements over amine systems. nother technology, oxycombustion, may also hold promise for new plants. These systems combust coal with nearly pure oxygen instead of air so that the resulting flue gas is predominantly capture-ready CO2. Oxy-combustion systems are capital-intensive, require larger equipment than IGCC plants, and must recycle large volumes of flue gas to moderate combustion temperatures. Improvements in oxygen production would benefit the technology. A few small-scale trials are currently underway and at least one company is evaluating potential retrofit applications.42 Other post-combustion technologies are being explored, some using advanced solvents, but these generally are not expected to reach the market for several years (at least) and are beyond the scope of this article.

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D. Geologic carbon storage The primary storage option for keeping CO2 out of the atmosphere permanently is likely to involve deep saline formations (DSF)—semi-permeable, geological strata a kilometer or more below ground that contain water too salty to be used for human consumption or irrigation. Such formations are broadly distributed around the world. CO2

injected into properly selected DSFs will dissolve and become trapped in surrounding pore spaces, in some cases eventually mineralizing into solid carbonaceous material. Globally, the storage capacity of DSFs has been estimated at 1,000–10,000 GtCO2 or more43—enough to hold 100–1,000 years (or more) of emissions from the world’s

existing coal power plants.44 The cost of geological sequestration in DSFs, including transportation, injection, and monitoring, is estimated to range from 7 percent to 16 percent of the total incremental cost of CCS on a 20year levelized basis (most of the added cost of CCS reflects the capital cost of the capture equipment, followed by increased fuel costs).45 DSF sequestration is currently being demonstrated at the Sleipner field off Norway (10 million tonnes, or Mt, stored since 199646), at In Salah in Algeria (1 Mt per year starting in 200447), and offshore, near the Snovit gas processing plant in Norway (injection began in mid-2008 and

will rise to 0.7 Mt per year at full capacity48). These projects have been designed and executed as learning exercises involving large petrochemical companies, although the Norwegian projects benefit from incentives in the form of an offshore CO2 emission tax. Numerous smaller projects have also been implemented49 and more are planned. For megaton-scale sequestration, DSF is currently possible though it has not yet been fully commercialized. Companies like Shell, Schlumberger, and others are developing the needed technologies and services. Unlike DSF sequestration, when CO2 is injected as a flooding gas in oil fields to enhance production, a positive revenue stream can result. For this reason enhanced oil recovery (EOR) using CO2 as the flooding gas is a mature technology that is currently practiced at 86 sites in the U.S. alone50 (some dating back to the 1970s). Global sequestration potential for CO2 used in EOR is estimated to be at least 675 GtCO2.51 Notable sites in North America include the Permian Basin of West Texas and New Mexico, the Rangely field in Colorado, the Williston Basin in Canada, the Power River Basin in Wyoming, and the U.S. Gulf Coast. For both DSF and EOR, the retention of CO2 in properly selected and operated repositories is expected to exceed 99 percent over 1,000 years,52 with the potential for leakage decreasing over time.53 Measured leakage at existing EOR sites has been very

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small: more than 20 million Mt of CO2 have been stored at Rangely to date, and leakage, if present, is below the detection limit of 170 tonnes per year.54 espite the world’s large body of experience with EOR, and the demonstrations of DSF, only one facility today actually performs CO2 separation, transportation, and injection as a single integrated operation and it does not involve a power plant. This is largely due to cost: the U.S. Department of Energy estimates that full CCS (90 percent carbon capture) with current technology increases the 20-year levelized cost of electricity roughly 30 percent for greenfield IGCC plants and even more for greenfield supercritical pulverized coal and NGCC plants (roughly 40 percent and 80 percent, respectively).55 These costs and some of the underlying thermodynamic efficiency losses can be reduced over time by scaling up the technology and gaining initial learning, but for now they remain significant hurdles. Other key barriers are the technical, legal, and commercial challenges posed by CCS system integration.

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E. Project- and industry-level challenges To implement megaton-scale CCS, capture technology must be integrated with upstream plant processes (e.g., boiler and steam systems, cooling systems, and pollution controls) and downstream systems for handling 32

the captured CO2. Regulatory and legal guidelines are needed to address a number of issues, including CO2 purity specifications, emissions limits, CO2 accounting, transportation of CO2 to injection sites, subsurface property rights, long-term stewardship of stored CO2, and concerns related to unexpected underground interactions between

 The ability to acquire debt (and the cost of borrowing) depends on the track record of similar projects, the availability of guarantees from technology providers, and equity participation in the project—none of which is easily obtained for pioneering CCS projects. transition phase, based on NowGen projects, is needed to develop experience overcoming these barriers and to begin establishing the elements of a working CCS industry.

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F. NowGens and a CCS industry

separately owned and operated repositories. These issues—which become more complex when multiple CCS projects feed a single pipeline system delivering CO2 to multiple sequestration sites—are by no means insurmountable, but they tend to compound a number of already formidable commercial hurdles:  Planning and development costs associated with the technical and legal complexity of integrated projects can create prohibitive barriers to consideration of CCS;  Absent a significant carbon price, CCS projects have high cost, but low value—making it difficult to show the returns needed to attract equity; and,

This article defines NowGens as commercial projects using tested technologies that include some element of CCS. By contrast, the proposed FutureGen project at Matoon, Ill., involves multiple untested components, including 90 percent capture on an IGCC plant, the latest version of a commercial hydrogen turbine, and large-scale geologic sequestration. An SNG plant that captures and sequesters CO2 through EOR clearly qualifies as a NowGen, as does the same plant with a dedicated gas turbine (such a plant would also meet California’s new CO2 standard). An IGCC plant with 50 percent capture goes further in utilizing new technology but can still be considered largely commercial. Obviously, what constitutes a NowGen project depends on the market’s risk tolerance and will change over time. But the distinction between commercial

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projects and projects primarily designed to demonstrate future technology is important when considering next steps to develop a viable CCS industry. e believe government support for early commercial NowGen projects, even those with only modest levels of CO2 capture, is necessary to resolve integration challenges in a time frame consistent with meaningful carbon abatement. By bringing together key actors (e.g., technology providers, project developers, off-takers, financiers, insurers, regulators, and the public) and motivating real-world problem solving, such projects can help resolve a number of technical, legal, and regulatory issues—thereby substantially reducing risks for subsequent projects—and can build confidence that success with CCS is possible. Fortunately, the foundations for a nascent industry already exist. In the coal gasification industry, millions of tons of CO2 per year are routinely separated from syngas before it is used; likewise, highhydrogen fuel gas is already being used in combustion turbines at a number of facilities around the world. As already noted, at least two IGCC projects with plans for partial capture are under construction in the U.S. and China. Meanwhile, the components to build an SNG production plant with CO2 capture have all been commercially proven and integrated at some level. Postcombustion capture is also possible today, though uncertainties exist in

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scaling up and integrating that technology (especially for retrofits), and the efficiency and cost hurdles with current technology are significant. For these early projects, partial capture likely provides a reasonable balance between technology advancement and financial risk. We target 20 GW of NowGen projects in the U.S. by 2020

because this is a sufficient scale to allow for different combinations of important base technologies for gasification and capture, utilizing a variety of fuels (e.g., bituminous and sub-bituminous coal, lignite, biomass, and petroleum coke). It is likely also sufficient to reduce CCS costs for subsequent projects by reducing the contingency charges associated with first-of-akind designs (which tend to multiply throughout the project cost structure) and by driving competition and diversification among suppliers of critical components (such as gasifier pressure vessels). Based on extensive interviews with project developers, we believe that nearly 20 publicly

announced projects in the U.S. could break ground as NowGens between 2009 and 2012. These include a mixture of IGCCs with partial and full capture, postcombustion capture, SNG to power, SNG, and chemical production. Of course, not all of these projects will materialize— indeed most of them likely will not be built unless credit markets improve or government assistance is provided. If all these projects were completed, however, they would capture more than 60 million tons of CO2 per year, enough to drive multiple pipeline projects and numerous sequestration demonstrations—including several DSF projects. This level of activity would represent an important step forward in overcoming hurdles to large-scale CCS deployment. G. The scale of the challenge: 100 GW globally by 2020, 20 GW in the U.S. There is, of course, no precise number that defines the level of CCS deployment needed to meet carbon abatement objectives over time. Efforts to model various emission-reduction scenarios, however, can provide a sense of magnitude. As part of the U.S. Climate Change Science Program (CCSP), for example, researchers from MIT, Stanford, the Electric Power Research Institute, Pacific Northwest National Laboratory, the University of Maryland, and the National Center for

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to address upstream and downstream environmental impacts from coal use. Though we do not discuss the international post-Kyoto context here, it is worth noting here that U.S. policy toward CCS must be anchored in a global policy agenda that includes India and China.

Figure 3: Global CCS Deployment in a 450 ppmv CO2 Stabilization Scenario (derived by CATF from data developed by U. S. Climate Change Science Program)

Atmospheric Research have modeled various technology combinations for meeting future climate policy goals. Their results produce a mid-range estimate of 100 GW for the amount of fossil electric-generating capacity with CCS likely to be needed globally by 2020 to stabilize atmospheric CO2 concentrations at 450 ppmv (with a low-end estimate of 25 GW and a high-end estimate of 250 GW) (Figure 3). ased on these results, 10 GW of CCS in the U.S. by 2020 will likely not be sufficient; though, at the other extreme, it would be wholly unrealistic to target 100 GW (the estimated global requirement) within a decade. A more reasonable national goal, in our view, is at least 20 GW of CCS by the year 2020—equal to roughly two-thirds of the projected increase in domestic coal capacity for this time-period according to government forecasts. This goal is consistent

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with the lower bounds of the CCSP results and with the scale of potential NowGen builds described previously; we turn now to the policies needed to achieve it.

IV. The U.S. Policy Agenda: Leading by Example To build 20 GW of NowGen projects over the next decade and to ensure that CCS is a costeffective and widely accepted control option for new coal-fired power plants by 2020 and for existing plants by 2030 will require aggressive federal action in four areas: (1) establishing a national climate program; (2) funding CCS projects and related infrastructure, domestically and overseas; (3) resolving key legal and regulatory uncertainties within an adaptable framework that is responsive to learning by doing; and (4) reforming policies

A. Carbon constraints as one key to long-term CCS deployment First, it almost goes without saying that Congress must enact a comprehensive national climate policy—and do so soon. Absent a carbon constraint, whether defined by price or quantity, it will be impossible to commercialize CCS, regardless of progress in advancing the technology and reducing costs. In addition, the federal government should establish CO2 emissions performance standards for new and existing coal plants. Standards should reflect technology availability and should become increasingly stringent over time. This could be accomplished through new legislation or through existing Clean Air Act mechanisms, like new source performance standards (NSPS). B. Incentives for early deployment Second, immediate federal investments in CCS are needed; these should complement (but not be dependent upon) the adoption

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of a national climate program. Specific initiatives should address the need for deployment incentives, funding for pipeline infrastructure, targeted RD&D for advanced fossil-fuel systems, funding for the existing geological sequestration program, an expanded R&D program (ideally in cooperation with partners like Australia and China) to enable wide-spread commercial deployment by 2020, support for geologic sequestration efforts in China and India, and resolution of key legal issues. Each of these needs is discussed below. 1. Incentives: The first NowGens Absent a mandatory carbon constraint, incentives will be needed to deploy the first 20 GW of NowGen capacity by 2020. This would be in addition to funding for specific technology demonstration projects. Current federal incentive programs for CCS are underfunded, need design improvements, or both. For example, investment tax credits established by the Energy Policy Act of 2005 and expanded in the Energy and Economic Stimulus Act (EESA) of 2008 have been underutilized, in part because of limits on project size—the amount of the credit is limited to $130 million for power plants but the minimum project size is 400 MW. Similarly, a sequestration tax credit adopted as part of the EESA 2008 has already drawn criticism. That

program provides a $20-per-ton credit for geologic sequestration and a $10-per-ton credit for EOR, subject to an overall cap of 75 million tons. However, developers note that these incentives are too small to reach breakeven costs for NowGentype projects and developers cannot depend on them as they are not guaranteed from year to

year. Finally, a program of DOE loan guarantees authorized under the Energy Policy Act of 2005 to help finance advanced coal and gasification projects has been limited by fee levels, credit subsidy costs, and a multiyear application/approval process, even though significant funding (roughly $10 billion) is theoretically available. These shortcomings are particularly problematic in the context of the current financial crisis. mprovements to existing programs (and in some cases increased funding) are critical to move the first NowGen projects, but even then, current incentives are likely to fall far short of what is needed to deploy 20 GW of CCS

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over the next decade. Moreover, current programs (like tax incentives) lack flexibility to adjust to changing conditions such as tight credit or rapid cost inflation. Therefore a new funding mechanism, presumably linked to a new energy policy or national climate program, is likely needed. Funding needs could be as high as $80 billion over 10 years, assuming minimum CO2 allowance prices similar to what would be expected under the proposed Bingaman-Specter legislation.56 However, this estimated cost is less than the CCS funding levels proposed in several prominent climate bills (e.g., $17 billion per year in the Bingaman-Specter bill; $37 billion per year in the Lieberman-Warner bill).57 CCS incentives should be selfactivating, like the wind production tax credit.58 However, they also need to be flexible to accommodate today’s volatile cost environment, substantial uncertainty about future fuel and electricity market prices, and differences in the market structures and tax treatments that apply to different project developers (e.g. municipal utilities versus regulated, investor-owned utilities, versus independent power producers that sell into wholesale markets). ne possible mechanism that meets this criterion of flexibility would involve direct payments to CCS project developers based on a reverse auction.59 Developers would bid

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for the minimum $-per-ton payment needed to make their project viable. Reverse auctions were pioneered by buyers for the automotive and aerospace industries in the 1990s and have been used in some states to procure electricity supply. This approach would help ensure that taxpayer funds are efficiently used, but also sufficient to move projects forward. Specific sums could be allocated to meet defined technology goals and frequent reviews (e.g. every two years) could be instituted to adjust program parameters as necessary. 2. Federal funding for CO2 pipelines To support commercial-scale CCS deployment by 2020, some initial trunk lines should be developed to transport CO2 to sequestration sites. Support for pipeline infrastructure could be included in an early deployment program, but it may be more efficient to develop targeted incentives. These could include loan guarantees, grants to buy down construction costs, or a time-limited ton-per-mile or square inch/mile tax credit or grant payment. 3. Expanded scope and funding for CCS-related federal RD&D programs To reduce costs, federal RD&D must expand to address key areas that are not currently being adequately funded, including advanced coal gasification systems; innovative post36

combustion capture; geologic sequestration; incremental technology improvements, and underground coal gasification. For example, improved technologies for membrane separation (for oxygen plants), CO2 compression, and more effective amine and aqueous ammonia capture systems could substantially improve

CCS economics. Similarly, the use of structured phase change materials in advanced postcombustion capture systems holds promise for reducing post-combustion capture costs. everal emerging technologies, including hydro gasification, molten-bath gasification, and gasification using blast furnace technology show promise for reducing surface coal gasification costs; likewise, potential cost reductions also exist for underground gasification. One very early study finds that with technology improvements, the economics of UCG with 60 percent carbon capture could eventually be

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similar to that of a supercritical coal plant without capture.60 4. Funding for the existing geological sequestration program The federal government should fully fund the geological carbon sequestration (GCS) R&D provisions of the Energy Independence and Security Act of 2007, which authorized $30 million per year for three years to conduct a national assessment of geologic resources for largescale CO2 sequestration in the U.S. and $240 million per year for five years to fully fund seven large-scale demonstration projects. Instead, federal appropriations for FY 2008 included $0 for geologic assessments and $119 million for GCS demonstrations. While DOE’s regional sequestration partnerships have produced solid initial geologic assessments for some key regions, a more detailed, national-level assessment is needed. Likewise the regional partnerships are in the process of developing six large-scale field demonstrations. However additional funding is needed to analyze and interpret data gathered from these partnerships and to inform the resolution of industrial, regulatory, legal, and public-use issues. 5. Funding for R&D to enable widespread commercial GCS availability by 2020 Federal R&D efforts are moving from the incremental to

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the large-scale, but they are not designed to reach a specified endpoint with respect to commercializing GCS. DOE should adopt an R&D agenda that helps facilitate the development of geologic sequestration capacity such that there is enough geographically diverse reservoir capacity developed for new CCS project coming on line after 2020 and enough developed capacity for all existing facilities no later than 2030. More work is needed to define this agenda, but in addition to a national resource assessment and large field demonstrations, other components should include:  Providing incentives or funding for early site exploration/characterization. The American Recovery and Reinvestment Act of 2009 provided a small but solid start on this with $50 million in funding for sequestration site characterization;  Targeted research to improve hazard assessment and risk management;  Technology development program (e.g. simulators fit for purpose to GCS and experimental test-beds for technology advancements). inally, additional RD&D that will have relevance beyond 2020 is needed to explore the potential of other formations such as coal beds and basalts and basin-scale management of multiple sequestration sites.

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6. Federal support for geological sequestration in China and India The U.S. should actively support GCS demonstration projects in India and China, where much of the growth in global CO2 emissions is occurring. This effort should parallel domestic activities, including:

 GCS assessment: This is an important foundational step toward enabling GCS in rapidly developing economies. Australia is currently working with China and the British Geologic Survey has conducted some preliminary work for India;  Large-scale demonstrations: As in the U.S., such projects will be critical to develop practical knowledge and experience specific to a developing-country context;  Commercialization efforts: Cooperative ventures between Chinese, Indian, and U.S. firms should be encouraged to accelerate technology availability and penetration, both domestically and overseas.

C. Why a federal investment program? Some have criticized the coal industry for failing to invest in CCS while claiming the mantle of ‘‘clean coal’’61—and have argued that the public should not support CCS if the coal industry won’t. While this attitude may resonate on emotional grounds, it is based on two shaky premises: first, that a coal industry that fails to decarbonize will be bypassed by other technologies when tighter carbon constraints kick in; or second, that carbon constraints will themselves trigger the industry investments needed for CCS deployment. As we argued in Section II, however, it is simply not prudent to count on renewables and energy efficiency to fully displace future coal use—even with carbon constraints. The physical and technical limits are simply too daunting, that’s why nearly every study concludes that reaching even less protective CO2 targets will require a significant CCS contribution. Politicians may support carbon constraints, but not at the expense of turning out the lights. If CCS is not ready and dirty coal is needed to keep the lights on, dirty coal will be used. he second premise—that carbon constraints alone will spawn a robust CCS industry—is likewise questionable. First, any emission constraints introduced in the near term likely won’t produce carbon prices steep enough to justify the scale of investment needed to advance

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CCS for some time. Sufficiently high carbon prices are probably even further off in China and India. If we wait for carbon markets alone to deliver CCS, we may spend two more decades locking in emissions whose effects will be with us for centuries. Second, we think it unlikely, even in the U.S., that a near-zero CO2 performance standard for new coal plants would be imposed substantially ahead of the deployment of demonstrated and cost-effective CCS technology. If it were imposed at the plant level, the industry would be more likely to use natural gas plants to fill supply gaps than to deploy CCS. hile it might be tempting to challenge the coal industry to de-carbonize itself or die, neither is a likely outcome— especially in the developing world. Simply put, companies are unlikely to invest in CCS on the scale required if doing so incurs costs that are not foreseeably recoverable in the market. The scale of investment likely to be needed—in the range of $7 billion per year, according to some estimates—exceeds the private R&D budget of the entire U.S. energy industry.62 Moreover, most previous energy-technology advances, including the combined-cycle gas turbine and wind energy, have received substantial public support.63 In fiscal year 2007, renewable energy technologies received nearly $5 billion in federal support64 and the wind energy production tax

credit alone cost more than $650 million65; renewable technologies have also benefited from policies and subsidies at the state level. In short, denying the public investment necessary to accelerate global deployment of CCS technology is shortsighted and risks hurting the public and the environment.

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D. Clarifying the roadmap: Resolving key legal uncertainties Congress and the states can support CCS deployment by moving expeditiously to resolve key legal uncertainties, especially with respect to long-term responsibility for sequestered CO2, property rights, and regulation of storage sites. Programs to regulate CCS must protect the public and the environment, while providing reasonable certainty for project developers. First, the U.S. Environmental Protection Agency (EPA) must finalize its proposed underground injection rule for GCS as soon as possible; it must

also develop Clean Air Act regulations governing CO2 emissions. Finally, EPA and Congress should act to connect the dots between rules for air emissions and sequestration so that the resulting regulatory system is based in the overall objective of climate protection, not just air or groundwater protection separately. Congress must also provide for an adequate number of skilled regulators to oversee these efforts. EPA currently regulates underground CO2 injection through the Safe Drinking Water Act’s Underground Injection Control (UIC) program, which is primarily implemented and enforced by the states. But large-scale CCS deployment will substantially increase the number of air and UIC permits that require processing. In addition, EPA’s proposed siting and monitoring requirements for class VI wells are more complex and detailed than those for other well classes. Therefore federal-level oversight will require a larger workforce with broader skills. If states retain primacy over GCS regulation, as is likely, they too must have adequate resources. 1. Long-term responsibility and property rights For long-term climate-change mitigation, the integrity of GCS sites must be ensured over very long timescales—centuries or more. Clearing the way for private CCS investment therefore requires normalizing details of ownership,

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confirming long-term liability for potential leakage, and assigning responsibility for monitoring and maintaining sites over long timeframes. o that end, Congress should consider some form of federal or state assumption of long-term liability for GCS projects and transfer of property rights. This could be funded by a per-ton fee on sequestered CO2. All other liability would remain with the owner/operator of the project. Such a program could be limited to an initial set of GCS projects; these could help set standards for later market-based financial instruments that could be held by the site owner or operator. Another approach worth considering involves state-based ‘‘GCS utilities.’’ Like a conventional electric utility, a GCS utility would be responsible for distributing CO2 to sequestration sites, which it would also manage in perpetuity. The utility would assume all financial responsibility, recover its cost in rates with a reasonable rate of return, and would operate transparently under state regulatory oversight. The value of this approach is that it would create certainty and reliability, and reduce the complexity associated with developing GCS at a system-wide scale.

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E. Beyond carbon: Addressing upstream and downstream coal impacts Even putting aside carbon and other air emissions, the current

environmental footprint of the coal industry, in the U.S. and globally, is unacceptable. Mining abuses such as mountaintop removal and other damaging practices destroy habitat, vegetation, groundwater quality, and scenic values.66 On the downstream side, the U.S. coal industry produces 100 million tons of combustion waste each

and leachable than waste from a pulverized coal plant; if a carbonbed system is applied, even mercury emissions can be reduced and captured for disposal in a secure landfill. Underground coal gasification could significantly reduce mining and combustion waste issues as well, for obvious reasons. Given the environmental problems associated with increased coal use even with CCS, it would be good public policy to address these issues now.

V. Conclusion: Damage Control is a Start

year, enough to fill a freight train stretching from Washington, D.C. to Australia. Much of this highly toxic waste stream is completely exempted from federal regulation and is only indifferently regulated by states. The result ranges from widely publicized episodes like the recent release of toxic sludge near Kingston, Tenn., to less visible but ongoing threats to groundwater from approximately 600 coal-waste disposal sites nationwide.67 o some extent, these nonclimate harms could be mitigated by advanced lowcarbon technologies. For example, IGCC plants generate much smaller quantities of solid waste in a vitrified form that is less toxic

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It is clear that managing climate change will require addressing one of its key drivers: coal-fired electricity generation. This likely can’t be done by just avoiding coal use altogether—at 41 percent of global electricity production in 2005, projected to increase to 46 percent in 2030, coal is unavoidable.68 We need costeffective CCS and enabling technologies, we need them at commercial scale, and we need them soon if we are to manage our collective exposure to potentially enormous climate risks. The measures recommended in this article are not beyond our technical or economic capability. But the prospects for effectively managing our climate problem recede further every day that we put them off.& Endnotes: 1. H. Damon Matthews and Ken Caldeira, Stabilizing Climate Requires Near-Zero Emissions, GEOPHYSICAL

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RESEARCH LETTERS, Feb. 2008. See also V. Ramanathan and Y. Feng, On Avoiding Dangerous Anthropogenic Interference with the Climate System: Formidable Challenges Ahead, PNAS, Sept. 23, 2008. 2. Anderson and Bows, two Tyndall Centre researchers, conclude that ‘‘if emissions peak in 2020, stabilization at 550 ppmv CO2e requires subsequent annual reductions of 6 percent in CO2e and 9 percent in energy and process emissions.’’ The team further notes by comparison that ‘‘the collapse of the former Soviet Union’s economy brought about annual emission reductions of over 5 percent for a decade. By contrast, France’s 40-fold increase in nuclear capacity in just 25 years and the UK’s ‘dash for gas’ in the 1990s both corresponded, respectively, with annual CO2 and greenhouse gas emission reductions of only 1 percent (not including increasing emissions from international shipping and aviation).’’ K. Anderson and A. Bows, Reframing the Climate Change Challenge in Light of Post-2000 Emission Trends, PHIL. TRANS. R. SOC., Aug. 2008, at 2838. 3. S. Solomon et al., Irreversible Climate Change Due to Carbon Dioxide Emissions, PROCEEDINGS OF NATIONAL ACADEMY OF SCIENCE, Vol. 6, No. 106, 1704–1709 (Feb. 2009); Mathews and Caldeira, supra note 1. 4. Summarized in J. Hansen et al., Target Atmospheric CO2: Where Should Humanity Aim? OPEN ATMOSPHERIC SCIENCE J., 2008, 2, 225. 5. Although estimates of the coal power build rate in China vary, several hundred GW clearly have been built in the past several years. Data from the U.S. DOE Energy Information Administration indicates that 28 GW of coal power were added in China in 2005, and the International Energy Agency reports that at least 94.5 GW of coal power were added in 2006. See U.S. DOE EIA International Energy Outlook 2007 and International Energy Outlook 2008, Table H4, and IEA World Energy Outlook 2007, at 349. Data from the China Electricity Council reported by Bloomberg news suggests that an additional 71 GW of coal power may have been added in 40

2007. See http://www.bloomberg. com/apps/news?pid=20601080& sid=aLD_Sgtws5yY&refer=asia. The IEA reports that 200 GW of coal power were under construction in 2008 (see IEA World Energy Outlook, at 143), and industry reports suggest that 33 GW or more had finished construction by November of that year (IndustrialInfo.Com, Oct. 20, 2008). In some cases only total generation additions are reported, and in deriving the numbers here it has been assumed here that 80 percent of the capacity

10. CATF, from Reducing U.S. Greenhouse Gas Emissions: How Much at What Cost? McKinsey & Co., 2007. Result is derived from power sector CCS (290 Gt) and industrial sector (95 Gt) compared to other options. 11. IPCC CCS Report, at 12. 12. IPCC, Summary for Policymakers, in Climate Change 2007: Mitigation. Contribution of Working Group III to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change, B. Metz, O.R. Davidson, P.R. Bosch, R. Dave, L.A. Meyer, Eds. (Cambridge, UK, and New York: Cambridge Univ. Press, 2007), at 17. 13. EIA Outlook 2007, supra note 5, at Tables A14, H7, and H10. 14. Despite Project Slippage, India Now Targeting 92,000-Megawatt Power Addition by 2012, IndustrialInfo.com, Nov. 21, 2008.

additions were coal. Taken together, these figures suggest that during the period from 2005 to November 2008, 227 GW of coal capacity were added in China, with an additional 167 GW under construction. Other estimates suggest the build rate is even higher, perhaps 80 GW per year. In comparison, the entire installed coal generation capacity in 2005 in OECD Europe was 198 GW. In the U.S. it was 314 GW. See DOE EIA IEO 2008 at Table H4. 6. International Energy Agency, World Energy Outlook 2008, Annex A, at 507, 531, and 532. 7. Id., at 507. 8. CATF, from Scenarios of Greenhouse Gas Emissions, United States Climate Change Science Program, Synthesis and Assessment Product 2.1a, 2007, online data used to derive Figure TS-11 of Technical Summary, at 22. 9. Climate Solutions, WWF’s Vision for 2050, WWF, 2007, at 24.

15. It is doubtful that expansion of biomass – assumed in many studies to provide a significant share of future electric generation and transportation fuel – can be deemed clean from a climate perspective. A series of recent studies suggests that the indirect land use effects of biomass expansion result in a substantial net warming. H K Gibbs, et al., Carbon Payback Times for CropBased Biofuel Expansion in the Tropics: The Effects of Changing Yield and Technology, ENVIRON. RES. LETT. (2008); Joseph Fargione, et al., Land Clearing and the Biofuel Carbon Debt, SCIENCE, Feb. 2008; Timothy Searchinger, et al., Use of U.S. Croplands for Biofuels Increases Greenhouse Gases Through Emissions from Land Use Change, SCIENCE, 2008. 16. See, e.g., C. Green and S. Baksi, Calculating Economy-Wide Energy Intensity Decline Rate: The Role of Sectoral Output and Energy Shares, ENERGY POLICY (2007), 35:6457–66; V. Smil, Energy at the Crossroads, Background notes for a presentation at the Global Science Forum Conference on Scientific Challenges for Energy Research, Paris, May 17–18, 2006, at www.oecd.org/dataoecd/52/25/ 36760950.pdf.

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17. A recent Stanford University study indicates that California’s decades of policy effort on electrical end efficiency – rightly hailed as a national and international model – has resulted in a roughly 10 percent decrease in per capita electricity use relative to the U.S. as a whole. A. Sudarshan and J. Sweeney, Deconstructing the ‘Rosenfeld Curve’, July 1, 2008, at http:// piee.stanford. edu/cgi-bin/htm/ Modeling/research/ Deconstructing_the_ Rosenfeld_Curve.php.

Administration data; CCS capacity projection based on US Climate Change Science Program; natural gas and oil production derived from DOE EIA and WRI data. 28. G. Gottlicher and R. Pruschek, Comparison of CO2 Removal Systems for Fossil-Fuelled Power Plant Processes, ENERGY CONVERS. MGMT., Vol. 38, Suppl., pp. S173–S178, 1997, at S174. 29. J. Tollefsen, Stoking the Fire, NATURE, Vol. 454, No. 24, July 2008, at 391.

18. See S. Pacala and R. Socolow, Stabilization Wedges: Solving the Climate Problem for the Next 50 Years with Current Technologies, SCIENCE, Aug. 13, 2005, supporting online materials. For a more extended analysis reaching a similar conclusion, see M. Jaccard, SUSTAINABLE FOSSIL FUELS (Cambridge Univ. Press, 2005).

38. See the International Energy Agency description of this project at: http://www. co2captureandsequestration.info/ project_specific.php?project_id=40.

20. CATF, from Cost and Performance Baseline for Fossil Energy Plants, Vol. I, Bituminous Coal and Natural Gas to Electricity, May, 2007 (hereinafter ‘‘DOE Fossil Baseline 2007’’), at case 12.

22. See note 5 on China build rates. 23. J.J. Dooley, R.T. Dahowskib, C.L. Davidson, Comparing Existing Pipeline Networks with the Potential Scale of Future U.S. CO2 Pipeline Networks, paper delivered to GHGT9, in press.

30. Specifically, these include a 250 MW project by Hydrogen Energy in California, a project by Summit Power Group in Texas, a 250 MW project by EPCOR in Alberta, and the ZeroGen project in Australia. 31. H.R. Linden, W.W. Bodle, B.S. Lee and K.C. Vyas, Production of High-Btu Gas from Coal, ANN. REV. ENERGY, 1976, 1:65–86, at 72–73. 32. Results depend critically on the prevailing natural gas price as well as other factors. See, The Case for Synthetic Natural Gas, Booz Allen Hamilton presentation to International Pittsburgh Coal Conference, Sept. 2008, at 3 and 9.

26. Id., at 244.

33. Myria Perry and Darren Eliason, CO2 Recovery and Sequestration at Dakota Gasification Company, Oct. 2004, at 2.

27. U.S. generating capacity derived from DOE Energy Information

34. CATF, assuming an NGCC plant heat rate of 7,619 Btu/kWh.

24. Id. 25. IPCC CCS Report, at 212.

36. SNG projects have been proposed by groups including Allied Syngas in North Dakota, the ERORA Group in Kentucky, and Secure Energy in Illinois. 37. Cost and Performance Baseline for Fossil Energy Plants, Final Results, Presentation, May 15, 2007, U.S. DOE NETL, at 21 and 26.

19. See note 15.

21. CATF, based on a critical density for CO2 of 467 kg/m3 IPCC, 2005, IPCC Special Report on Carbon Dioxide Capture and Storage, Prepared by Working Group III of the Intergovernmental Panel on Climate Change, B. Metz, O. Davidson, H.C. de Coninck, M. Loos, and L.A. Meyer, Eds., Cambridge, United Kingdom and New York: Cambridge Univ. Press), 442 pp. (hereinafter ‘‘IPCC CCS Report’’), at 386.

35. IEA GHG Weyburn-Midale CO2 Monitoring and Sequestration Project, statistics as of July 2008, downloaded from http:// canmetenergy-canmetenergie.nrcanrncan.gc.ca/eng/clean_fossils_fuels/ carbon_capture_sequestration/ co2_capture_sequestration_ network/publications.html on Dec. 10, 2008.

39. MHI and E.ON Energie of Germany to Verify CO2 Recovery Technology for Coal-fired Power Generation Plants – 100 Tons/Day Facility to Start Operation in 2010, Mitsubishi Heavy Industries, Ltd. Press release, July 3, 2008, No. 1245, available at http:// www.mhi.co.jp/en/news/story/ 0807031245.html. 40. Recent Initiatives and the Current Status of MHI’s Post Combustion CO2 Recovery Process; Aiming to Realize the Rapid Commercial Application of CCS, MHI Presentation to Seventh Annual Conference on Carbon Capture & Sequestration, May 2008, at 14. 41. Fluor Corporation has several decades of experience with postcombustion capture (although not on coal plants), including a 330 tpd capture system on a natural-gas combustion turbine in Massachusetts (Econamine FG PlusSM Technology for Post-Combustion CO2 Capture, Fluor Presentation to Seventh Annual Conference on Carbon Capture & Sequestration, May 2008, at 8). Fluor expects to test its system on a coal boiler in Wilhelmshaven, Germany, in 2010 at roughly 100 tpd scale (Fluor Corporation and E.ON

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Energie AG Join Forces on CO2 Capture for Coal-Fired Power Plants, Reuters Business Wire, July 3, 2008) and has stated that it is ready to provide a commercial-scale system. Alstom’s chilled ammonia postcombustion capture system is currently being tested at a small scale, with a larger project (roughly 360 tpd) planned for AEP’s Mountaineer plant in West Virginia (AEP’s CO2 Capture & Sequestration Program, AEP Presentation to Seventh Annual Carbon Capture and Sequestration Conference, May 2008, at 13).

50. Storing CO2 with Enhanced Oil Recovery, U.S. DOE, 2008, at 17. 51. IPCC CCS Report, at 221. 52. Id., at 246. 53. Id., at 208. 54. Id., at 216. 55. DOE Fossil Baseline, at 4. 56. Estimate based on initial results of forthcoming analysis from The NorthBridge Group, commissioned by Clean Air Task Force and the National

44. Author’s estimate based on global coal fleet emissions of around 10 GtCO2/yr. 45. CATF, based on DOE Fossil Baseline, at 11–12. 46. StatoilHydro Reports 10 Million Tonnes of CO2 Stored at Sleipner, CARBON CAPTURE J., May/June 2008, at 24. 47. CO2 Monitoring at In Salah, BP presentation to Seventh Annual Conference on Carbon Capture & Sequestration, May 2008. 48. StatoilHydro begins CO2 Injection at Snohvit, CARBON CAPTURE J., May/June 2008, at 24. 49. Examples include the Frio brine experiments in Texas and projects involving the commercial injection of acid gas with high CO2 content in the western U.S. and Canada. 42

59. Forthcoming analysis from Northbridge, commissioned by Clean Air Task Force and the National Commission on Energy Policy regarding of financial incentive levels and program design necessary to facilitate initial deployment of carbon capture and sequestration projects. 60. Carbon Capture & Sequestration and UCG, Lawrence Livermore National Laboratory presentation to International Pittsburgh Coal Conference, Oct. 2008.

42. Trial projects are underway at Vattenfall, Germany, and at Babcock & Wilcox’s test facility in Ohio (see http://www.vattenfall.com/www/ co2_en/co2_en/879177tbd/ 879211pilot/index.jsp and B&W Press Release, Dec. 5, 2007, at http://www.babcock.com/ news_and_events/2007/ 20071205b.html). Babcock & Wilson is also evaluating retrofit options for oxy-combustion technology. 43. IPCC CCS Report, at 221. According to IPCC the lower figure of 1,000 GtCO2 is ‘‘very likely’’. See p. 223.

activating the federal loan guarantee for energy projects administered by the Department of Energy, and includes an application process, is not.

61. Center for American Progress, The Clean Coal Smoke Screen, at http:// www.americanprogress.org/issues/ 2008/12/clean_coal.html. 62. Daniel M. Kammen and Gregory F. Nemet, Reversing the Incredible Shrinking Energy R&D Budget, ISSUES IN SCI. & TECH., Fall 2005, at http:// www.issues.org/22.1/ realnumbers.html. Commission on Energy Policy regarding of financial incentive levels and program design necessary to facilitate initial deployment of carbon capture and sequestration projects. 57. See U.S. Environmental Protection Agency, EPA Analysis of the Low Carbon Economy Act of 2007, S. 1766 in 110th Congress, January 15, 2008 (as updated 1/25/08) and U.S. DOE Energy Information Administration, Energy Market and Economic Impacts of S. 2191, the Lieberman-Warner Climate Security Act of 2007, April, 2008. 58. A self-activating incentive minimizes any discretion by administrative agencies in applying the incentive, and instead establishes clear criteria for whom the incentive is applicable and under what circumstances. The federal wind production tax credit, which is provided by the Treasury when a project developer meets certain explicit criteria, is considered self-

63. See J. Alic et al., U.S. Technology and Innovation Policies: Lessons for Climate Change, Prepared for Pew Center on Global Climate Change, Nov. 2003, at http:// www.pewclimate.org/globalwarming-in-depth/all_reports/ technology_policy. 64. At http://tonto.eia.doe.gov/ energy_in_brief/ energy_subsidies.cfm. 65. At http://tonto.eia.doe.gov/ energy_in_brief/ energy_subsidies.cfm. 66. See Clean Air Task Force, Cradle to Grave: The Environmental Impacts of Coal, June 2001, at http:// www.catf.us/publications/view/7. 67. See Clean Air Task Force, Laid to Waste: The Dirty Secret of Combustion Waste from America’s Power Plants, March 2000, at http://www.catf.us/ publications/view/7. 68. CATF from DOE IEA International Energy Outlook 2008, at Tables H7 and H10.

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