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Page **1** of **19** c. Basis for CCS as a Compliance Alternative . In this section, we describe the basis for our position that CCS is a compliance alternative for coal - fired power plants because CCS is feasible and sufficiently available in light of the limited amount of new coal - fired construction expected. In brief, f i rst, at present, CCS is technologically feasible and its core components (CO 2 capture, compression, transportation and storage) have already been implemented. Second, although the costs of CCS are presently high, we have reason to expect that the costs of CCS will decrease over time . This action will itself contribute to downward pressure on CCS costs by shifting the regulatory landscape towards CCS, consistent with t he recent report by Interagency Task Force on Carbon Capture and Storage, established by Pr esident Obama on February 3, 2010, which we describe below. . Third, we expect construction of no more than a few new coal - fired power plants by 2020, and those may well be able to take advantage of demonstration programs or other sources of funding for CCS . Fourth, several states have required CCS, many projects that implement CCS or components of it are proceeding, and other projects for CCS are in the planning stages.*********E.O. 12866 Review**

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Page **2** of **19** (1) Technological Feasibility of CCS. The current state of affairs concerning CCS was de scribed and analyzed by the Interagency Task Force on Carbon Capture and Storage, established by President Obama on February 3, 2010, co chaired by the DOE and the EPA, and composed of 14 executive departments and federal agencies. The Task Force was charged with proposing a plan to overcome the barriers to the widespread, cost - effective deployment of CCS within 10 years, with a goal of bringing five to ten commercial demonstration projects online by 2016. The Task Force found that, although early CCS proje cts face economic challenges related to climate policy uncertainty, first - of - a - kind technology risks, and the current high cost of CCS relative to other technologies, there are no insurmountable technological, legal, institutional, regulatory or other barr iers that prevent CCS from playing a role in reducing GHG emissions. The Task Force also identified the need for comprehensive review of the overall environmental impacts of CCS. (a) Capture Technologies and Costs. Capture of CO 2 from industrial gas streams has occurred since the 1930s using a variety of approaches to separate CO 2 from other gases. These processes have been used in the natural gas industry*********E.O. 12866 Review**

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Page **3** of **19** and to produce food and chemical - grade CO 2 . Although current capture techno logies are feasible, the costs of CO 2 capture and compression represent the largest stumbling block to widespread commercialization of CCS. Currently available CO 2 capture and compression processes are estimated to represent three quarters of the overall C CS costs. In general, CO 2 capture technologies applicable to coal - fired power generation can be categorized into three approaches 1 :

 Pre - combustion systems are designed to separate CO 2 and H 2 in the high -pressure syngas produced at IGCC power plants.

 Post - combustion systems are designed to separate CO 2 from the flue gas produced by fossil - fuel combustion in air.

 Oxy - combustion uses high -purity O 2 , rather than air, to combust coal and therefore produces a highly concentrated CO 2 stream. Each of the se three c arbon capture approaches (pre combustion, post - combustion, and oxy - combustion) is technologically feasible . However, each results in

1 IPCC, 2005; DOE, 2007.*********E.O. 12866 Review**

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Page **4** of **19** increased capital and operating costs and decreased electricity output ( that is, an energy penalty), with a resulting incre ase in the cost of electricity. The energy penalty occurs because the CO 2 capture process uses some of the energy produced from the plant. (b) Current Availability of Transportation and Sequestration . As just discussed, the primary costs associated with CC S are the costs of capturing and compressing CO 2 . The remaining steps for CCS, pipeline transportation and sequestration, are better established . C arbon dioxide has been transported via pipelines in the U .S. for nearly 40 years. Approximately 50 million metric tons of CO 2 are transported each year through 3,600 miles of pipelines. Moreover, a review of the 500 largest CO 2 point sources in the U .S. shows that 95 percent are within 50 miles of a possible geolog ic sequestration site , 2 which would lower transportation costs. For all these reasons, the transportation component of CCS is not expected to be a significant stumbling block to the commercial availability of CCS.

2 JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH Kim, EL Malone (2006), Carbon Dioxide Capture and Geologic Storage: A Key Component of a Global Energy Technology Strategy to Address Climate Change. Joint Global Change Re search Institute, Battelle Pacific Northwest Division. PNWD - 3602. College Park, MD.*********E.O. 12866 Review**

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Page **5** of **19** With respect to sequestration, g lobally, t here are at least four commercial integrated CCS facilities sequestering captured CO 2 into deep geologic formations and applying a suite of technologies to monitor and verify that the CO 2 remains sequestered. 3 These four sites represent over 25 years of cumulative experience on safely and effectively storing anthropogenic CO 2 in appropriate deep geologic formations. 4 Estimates based on DOE studies indicate that areas of the U .S. with appropriate geology have a storage potential of 1,800 billion to more than 20,000 billion metric tons of CO 2 in deep saline formations, oil and gas reservoirs and unmin e able coal seams. 5 The U . S . experience with large - scale CO 2 injection, such as at enhanced oil and gas recovery projects, combined with ongoing research, development , and demonstration programs throughout the world, provide confidence that the storage
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- along with capture and transport -- of large amounts of CO 2 can be achieved.

3 These projects are: Sleipner in the North Sea, Snøhvit in the Barents Sea, In Salah in Algeria, and Weyburn in Canada. 4 Dooley, J. J., et al. (2009). An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009. U.S. Department of Energy, Pacific Northwest National Laboratory, under Contract DE -AC05 - 76RL01830. 5 U.S. Depar tment of Energy National Energy Technology Laboratory (2010). Carbon Sequestration Atlas of the United States and Canada, Thi rd Edition.*********E.O. 12866 Review**

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Page **6** of **19** It should be noted that t he EPA recently finalized two rules that aim to protect drinking water and track the amount of CO 2 that is sequestered from facilities that carry out geologic sequestration. The Underground Injection Control (UIC) Class VI rule, established under authority of the Safe Drinking Water Act, sets requirements to en sure that geologic sequestration wells are appropriately sited, constructed, tested, monitored , and closed in a manner that ensures protection of underground sources of drinking water. 6 The UIC Class VI regulations contain monitoring requirements to protec t underground sources of drinking water, including the development of a comprehensive testing and monitoring plan . This includes testing of the mechanical integrity of the injection well, ground water monitoring, and tracking of the location of the injecte d CO 2 using direct and indirect methods. Projects are also required to do extended post - injection monitoring and site care to track the location of the injected CO 2 and monitor subsurface pressures until it can be demonstrated that underground sources of drinking water are no longer endangered. Subpart RR of the Greenhouse Gas Reporting

6 Federal Requirements under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestr ation (GS) Wells, Final Rule, 75 FR 77230 (Dec. 10, 2010).*********E.O. 12866 Review**

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Page **7** of **19** Program, which was established under authority of the CAA and builds on UIC requirements, provides requirements for quantifying the amount of CO 2 sequestered by these facili ties. 7 In addition , the EPA recently proposed a rule that would conditionally exclude CO 2 streams from the definition of hazardous waste under RCRA , where these streams are being injected for purposes of geologic sequestration, provided that they are managed in accordance with certain conditions. 8 That proposed rule is based upon the EPA's conclusion that the management of CO 2 streams, under the proposed conditions, does not present a substantial risk to human health or the environment, and was based upon a review of existing regulatory programs applicable to the transportation of CO 2 streams, and their injection into permitted UIC Class VI wells . Together, these actions help create a consistent national framework to ensure the safe and effective deployment of geologic sequestration.

7 Mandatory Reporting of Greenhouse Gases: Injection and Geologic Sequestration of Carbon Dioxide, Final Rule, 75 FR 75060 (Dec. 1, 2010). 8 Hazardous Waste Management System: Identification and Li sting of Hazardous Waste: Carbon Dioxide (CO 2 ) Streams in Geologic Sequestration Activities, Proposed Rule, 76 FR 48073 (Aug. 8, 2011).*********E.O. 12866 Review**

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Page **8** of **19** (2) Expected reduction in CCS costs. As noted above,
currently available CO 2 capture and compression processes are estimated to represent three quarters of the overall CCS costs, and it is those that, at present, make CCS relatively costly. However, research is underway to reduce those costs . The DOE/National Energy Technology Laboratory ( NETL ) sponsors an extensi ve research development and demonstration program that is focused on developing advanc ed technology options that dramatically lower the cost of capturing CO 2 from fossil - fuel energy plants compared to today’s available capture technologies. The DOE/NETL es timates that using today’s commercially available CCS technologies would add around 80 percent to the cost of electricity for a new pulverized coal (PC) plant, and around 35 percent to the cost of electricity for a new advanced gasification -based (IGCC) pl ant. The CCS research development and demonstration effort is aggressively pursuing efforts to reduce these costs to a less than 30 percent increase in the cost of electricity for PC power plants and a less than 10 percent increase in the cost of electrici ty for new gasification -based power plants. 9 The large - scale CO 2 capture demonstrations that are
9 DOE/NETL Carbon Dioxide Capture and Storage RD&D Roadmap, U.S.*********E.O. 12866 Review**

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Page **9** of **19** currently planned and in some cases underway, under DOE’s initiatives, as well as other domestic and international projects, will generate operational knowledge and enable future commercialization and widespread cost - effective deployment of these technologies. Gas absorption processes using chemical solvents, such as amines, to separate CO 2 from other gases have been in use since the 1930s in the natural gas industry and to produce food and chemical grade CO 2 . The advancement of amine -based solvents is an example of technology development that has improved the cost and performance of CO 2 capture. Most single component amine systems are not practical in a flue gas environment as the amine will rapidly degrade in the presence of oxygen and other contaminants. The Fluor Econamine FG process uses a monoethanolamine (MEA) formulation specially designed to recover CO 2 and contains a corrosion inhibitor that allows the u se of less expensive, conventional materials of construction. Other commercially available processes use sterically hindered amine formulations (for example, the Mitsubishi Heavy Industries KS - 1 solvent) which are less susceptible to degradation and Department of Energy National Energy Technology Laborat ory, December 2010.*********E.O. 12866 Review**

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Page **10** of **19** corros ion issues. The DOE/NETL and private industry are continuing to sponsor research on advanced solvents (including new classes of amines) to improve the CO 2 capture performance and reduce costs. Significant reductions in the cost of CO 2 capture would be con sistent with overall experience with the cost of pollution control technology. A significant body of literature suggests that the per - unit cost of producing or using a given technology declines as experience with that technology increases over time , 10 and t his has certainly been the case with air pollution control technologies . Reductions in the cost of air pollution control technologies as a result of learning -by - doing, research and development investments , and other factors have been ob served over the decades. We have every reason to expect that the costs of capture technology will follow this pattern. Rubin et al.

10 These studies include John M. Dutton and Annie Thomas, "Treating Progress Functions as a Managerial Opportunity," 2, 235 - 247; Dennis Epple, Linda Argote, and Rukmini Devadas, "Organizational Learning Curves: A Method for Investigating Intra - plant Transfer of Knowledge Acquired Through Learning by Doing," Organizational Science, Vol. 2, No. 1, February 1991; International Energy Agency, Experience Curves for Energy Technology Policy, 2000; and Paul L. Joskow and Nancy L. Rose, "The Effe cts of Technological Change, Experience, and Environmental Regulation on the Construction Cost of Coal - Burning Generating Units," RAND Journal of Economics, Vol. 16,Issue 1, 1 - 27, 1985. See discussion in “The Benefits and Costs of the Clean Air Act from 19 90 to 2020,” U.S. EPA, Office of Air and Radiation, April 2011.*********E.O. 12866 Review**

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Page **11** of **19** used historical experience curves as the basis for estimating future cost trends for four types of new electric power plan ts equipped with CO 2 capture systems: PC and NGCC plants with post - combustion CO 2 capture; coal -based IGCC plants with pre - combustion capture; and coal - fired oxyfuel for new PC plants. 11 They assessed the historical rates of cost reductions achieved by othe r energy and environmental process technologies and then, by analogy, estimated future cost reductions that might be achieved by power plants employing CO 2 capture. The results of the study suggested that total costs of CO 2 capture can be expected to reduc e by the following percentages: NGCC by 40 percent, PC by 26 percent, IGCC by 13 percent, and Oxyfuel by 13 percent . In a subsequent study, the model used in the initial study was extended with learning curves for several key performance variables, includi ng overall energy loss in power plants, the energy required for CO 2 capture, the CO 2 capture ratio (removal efficiency) and the power plant availability. The model predicted continued reductions in

11 Rubin, E.S.; Yeh, S.; Antes, M.; Berkenpas, M.; Davison, J.; “Use of experience curves to estimate the future cost of power plants with CO2 capture”, Intl. J. of Greenhouse Gas Control, 1, 1 88 (2007).*********E.O. 12866 Review**

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Page **12** of **19** cost with increased implementation. 12 In addition, we note that the Administration’s CCS T ask F orce report recognized that CCS c ould become more widely available with the advent of a regulatory framework that promoted CCS . Today’s action is an important component in developing that framework. (3) Limited amount of construction of coal - fired power plants; opportunities for CCS funding. A third reason that supports CCS as an alternative compliance option is that through the IPM model period of up to 2020, we expect few if any new builds of coal - fired EGUs . We also expect continued opportunity for financial support for some CCS projects through a variety of potential mechanisms such as direct grants, tax incentives and/or regulatory programs (e.g. Clean Energy Standards such as gauaranteed electricity purchase price agreements) 13
. Accordingly, the few new coal - fired generation projects that may occur may well find that financial support for CCS is available. (4) State Requirements for CCS; Projects and Permits for

12 Van den Broek, M.; Hoefnagels, R.; Rubin, E.; Turkenburg, W.; Faaij, A.; “Effects of technological learning on future cost and performance of power plants with CO 2 capture”, Progress in Energy and Combustion Science 35 (2009) 457 - 480. 13 See Center for Climate and Energy Solutions, “Financial Incentives for CCS”
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Page **13** of **19** CCS. Several states have recently established requireme nts for CCS, and a number of with CCS have been approved and/or are under construction. . In May 2007, Montana Governor Schweitzer signed H ouse B ill 25, adopting a CO 2 emissions performance standard for electric generating units in the state . H ouse B ill 25 prohibits the state Public Utility Commission from approving new electric generating units primarily fueled by coal unless a minimum of 50 percent of the CO 2 produced by the facility is captured and sequestered. On January 12, 2009, Illinois Governor Blagojevich signed S enate B ill 1987, the Clean Coal Portfolio Standard Law. The legislation establishes emission standards for new power plants that use coal as their primary feedstock. From 2009 - 2015, new coal - fueled power plants must capture and store 50 percent of the carbon emissions that the facility would otherwise emit; from 2016 - 2017, 70 percent must be captured and stored; and after 2017, 90 percent must be captured and stored. The following is a brief summary of currently operating or planned CO 2 capture systems , including, in some cases, part of the components for coal -based power plant applications.*********E.O. 12866 Review**

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Page **14** of **19** AES’s coal - fired Warrior Run (Cumberland, MD ) and Shady Point (Panama, OK ) power plants are equipped with amine scrubbers developed by ABB/Lummus. They were designed to process a relatively small percentage of each plant’s flue gas. At Warrior Run, approximately 110,000 tonnes of CO 2 per year are captured, whereas at Shady Point 66,000 tonnes of CO 2 per year are captured. The CO 2 from both plants is subsequently used in the food processing industry 14
. At the Searles Valley Minerals soda ash plant in Trona, CA , approximately 270,000 tonnes of CO 2 per year are captured from the flue gas of a coal power plant via amine scrubbing and used for the carbonati on of brine in the process of producing soda ash . 15 A pre - combustion Rectisol® system is used for CO 2 capture at the Dakota Gasification C ompany’s synthetic natural gas production plant located in North Dakota, which is designed to remove approximately 1.6 million tonnes of CO 2 per year from the synthesis gas. The CO 2 is purified, transported via a 200 -mile pipeline, and injected into the

14 Dooley, J. J., et al. (2009). An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009. U.S. DOE, Pacific Northwest National Laboratory, under Contract DE -AC05 - 76RL01830. 15 IEA (2009a), World Energy Outlook 2009, OECD/IEA, Paris .*********E.O. 12866 Review**

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Page **15** of **19** Weyburn oilfield in Saskatchewan, Canada. In September 2009, American Electric Power Co . ( AEP ) began a pilot - scale CCS demonstration at i t s Mountaineer Plant in New Haven, WV. The Mountaineer Plant is a 1,300 MWe coal - fired unit that was retrofitted with Alstom’s patented chilled ammonia CO 2 capture technology on a 20 MWe portion, or “slipstream”, of the plant’s exhaust flu e gas. In May 2011, Alstom Power announced the successful operation of the chilled- ammonia CCS validation project. The AEP -Alstom project, the world’s first facility to both capture and store CO 2 from a coal - fired power plant, represents a successful scale - up of ten times the size of previous field pilots (e.g., at We Energies Pleasant Prairie). The demonstration achieved capture rates from 75 percent (design value) to as high as 90 percent , produced CO 2 at purity of greater than 99 percent , with energy pen alties within a few percent of predictions. The facility reported robust steady - state operation during all modes of power plant operation including load changes, and saw an availability of the CCS system of greater than 90 percent . AEP, with assistance fr om the DOE , had planned to expand the slipstream demonstration to a commercial scale, fully integrated demonstration at the Mountaineer facility.*********E.O. 12866 Review**

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Page **16** of **19** The commercial - scale system was designed to capture at least 90 percent of the CO 2 from 235 MW of the plant's 1,300 MW total capacity. Plans were for the project to be completed in four phases, with the system to begin commercial operation in 2015. However, in July 2011, AEP announced that it is terminating its cooperative agreement with the DOE and placing its pl ans to advance CO 2 capture and storage technology to commercial scale on hold, citing the current uncertain status of U.S. climate policy and the continued weak economy as contributors to the decision. Oxy - combustion of coal is being demonstrated in a 10 MWe facility in Germany. The Vattenfall plant in eastern Germany (Schwarze Pumpe) has been operating since September 2008. It is designed to capture 70,000 tonnes of CO 2 per year In June 2011, Mitsubishi Heavy Industries, an equipment manufacturer , announc ed the successful launch of operations at a 25 MW coal - fired carbon capture facility at Southern Company's Alabama Power Plant Barry. The demonstration is planned to capture approximately 150,000 tons of CO 2 annually (500 tons per day) at a CO 2 capture rat e of over 90 percent . The captured CO 2 will be*********E.O. 12866 Review**

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Page **17** of **19** permanently stored underground in a deep saline geologic formation. Southern Company has begun construction of Mississippi Power Plant Ratcliffe (formerly the Kemper County IGCC Project). Plant Ratcliffe is a 582 MW IGCC plant that will utilize local Mississippi lignite and include pre combustion carbon capture to reduce CO 2 emissions by 65 percent . Operation is expected to begin in 2014. The CO 2 captured from Plant Ratcliffe will be used for enhanced oil
recovery ( EOR ) in the Heidelberg Oil Fields in Jasper County, MS. The Texas Clean Energy Project , a 400 MW IGCC facility located near Odessa, TX will capture 90 percent of its CO 2 , which is approximately 3 million ton ne s annually. The captured CO 2 will be used for EOR in the West Texas Permian Basin. ( Additionally, the plant will produce urea and smaller quantities of commercial - grade sulfuric acid, argon, and inert slag, all of which will also be marketed. ) Construction is expected to begin in the first part of 2012. . Hydrogen Energy California, a 257 MW gasification facility in south - central California utilizing coal and petroleum coke, will capture 1.8 million tonnes per year of*********E.O. 12866 Review**

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Page **18** of **19** CO 2 using a Rectisol® process , for use in an EOR application . The facility is expected to be operational in 2016. In May 2011, SCS Energy announced that it was agreeing to take over Hydrogen Energy California and was planning to modify the project to add polygeneration capabilities. In June 2011, Alstom Power President, Philippe Joubert, discussed the results of a detailed study concerning carbon capture technology, conducted by Alstom, at the 2011 PowerGen Europe conference (Milan, Italy). The study was based on results from 13 European pilot - and demonstration - scale pro jects and the results were validated by independent experts. From the results of the study, Joubert concluded that “We can now be confident that carbon capture technology works and is cost effective.” 16 In its recent Integrated Resource Plan, the Tennessee Valley Authority (TVA) recommended new coal additions of up to 900 MW in the 2025 - 2029 timeframe and further recommended that TVA "preserve [the] option of generation

16 June 14, 2011 press release from Alstom, “Alstom Power study demonstrates carbon capture and storage (CCS) is efficient and cost competitive”, http://www.alstom.com/power/news
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Page **19** of **19** with carbon capture." 17 The TVA included supercritical pulverized coal plants with CCS technology as well as IGCC plants with CCS technology as resource options in its Integrated Resource Plan evaluation .

17 IRP, March 2011.