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. With respect to carbon dioxide (CO 2 ), the most prevalent greenhouse gas, coal combustion was responsible for 41% of the world's CO 2 emissions in 2005 (11 billion metric tons). 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. Coal-fired power generation is estimated to increase 2.3% annually through 2030, with resulting CO 2 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 CO 2 to the atmosphere annually. 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 system 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. 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 substantially reduce the cost of capturing CO 2 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 CO 2 is transported away from the power plant and sequestered underground. In contrast, the cost of transporting CO 2 and sequestering it underground is likely less dependent on technological breakthroughs than on other factors, such as: the costs of construction materials and labor (in the case of pipelines for CO 2 transport); the degree of geologic characterization required to permit sequestration; the requirements for measuring, monitoring, and verifying permanent CO 2 storage; the costs of acquiring surface and subsurface rights to store CO 2 ; costs of insurance and long-term liability; and other variables driving the cost of transportation and sequestration. 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 CO 2 sequestration. But the variables driving cost and timing for the transportation and storage of CO 2 are less amenable to technological solution. This report examines the current effort to develop technology that would capture CO 2 . First, the report outlines the current status of carbon capture technology. Second, the report 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 report concludes with a discussion of implications of capture technology for climate change legislation. Major reductions in coal-fired CO 2 emissions would require either pre-combustion, combustion modification, or post-combustion devices to capture the CO 2 . 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. Post-combustion CO 2 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 (SO 2 ), 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 CO 2 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 post-combustion processes are in the bench-scale stage. The MEA CO 2 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 CO 2 and absorbs it. The now CO 2 -rich MEA is then pumped to a stripper (also called a regenerator) which uses steam to separate the CO 2 from the MEA. Water is removed from the resulting CO 2 , 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 90-95% of the CO 2 from the flue gas. Although proven on an industrial scale, it has not been applied to the typically larger volumes of flue gas streams created by coal-fired power plants. The technology has three main drawbacks that would make current use on a coal-fired power plant quite costly. First is the need to divert steam away from its primary use—generating electricity—to be used instead for stripping CO 2 from MEA. A second related problem is the energy required to compress the CO 2 after it's captured—needed for transport through pipelines—which lowers overall power plant efficiency and increases generating costs. A study by the Massachusetts Institute of Technology (MIT) estimated the efficiency losses from the installation of MEA from 25%-28% for new construction and 36%-42% for retrofit on an existing plant. 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. 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%. 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 SO 2 in the flue gas will react with the MEA to form ammonium sulfate that must be purged from the system. 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. One approach to addressing the shortcomings of MEA identified above is to use an MEA-based formulation of different amines. The goal of the formulation is improve the reaction rates and CO 2 carrying capacity of the solvent under typical power plant conditions. One such proprietary amine-based technology has been developed by Fluor (called Economine FG Plus). Fluor states that its MEA-based solvent is specially formulated to recover CO 2 from low pressure, oxygen-containing streams, such as boiler stack gases found in conventional coal-fired power plants. The treatment process is similar to generic gas treating processes, using simple, time-tested gas treating equipment. To address contamination of the solvent, the Fluor technology focuses on cleaning up impurities in the flue gas (e.g., SO 2 , NOx, hydrochloric acid, and hydrofluoric acid) in order to inhibit the formulation of ammonium sulfate and other heat-stable salts. Thus the process requires installation of modern SO 2 (with additional enhancements), NOx, Hg, and particulate controls upstream of the carbon capture technology to address the impurities. Solvent temperature issues are dealt with through the use of an intercooler system within the absorber. Finally, other enhancements in the process reduce the process energy consumption. Fluor's technology has significant experience on a small commercial scale, including the only CO 2 recovery unit that has operated on the flue gas of a natural gas-fired turbine power plant under typical power plant conditions. Between 1991 and 2005, the Fluor facility at the Bellingham, MA, power plant captured 360 shorts tons of CO 2 daily for use in the food and beverage industry. In September 2009, NRG Energy and Fluor announced that Economine FG Plus would be installed on a 60 megawatt (MW) slipstream at NRG's WA Parish plant (Unit 7) in Texas, with a plan to be operational by 2013.