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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, first, at present, CCS is 

technologically feasible and its core components (CO2

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 the 

recent report by Interagency Task Force on Carbon Capture 

and Storage, established by President 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.
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(1) Technological Feasibility of CCS. The current state of 

affairs concerning CCS was described and analyzed by the 

Interagency Task Force on Carbon Capture and Storage, 

established by President Obama on February 3, 2010, cochaired 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 projects 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 

barriers 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 CO2 from 

industrial gas streams has occurred since the 1930s using a 

variety of approaches to separate CO2 from other gases. 

These processes have been used in the natural gas industry 
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and to produce food and chemical-grade CO2. Although current 

capture technologies are feasible, the costs of CO2 capture 

and compression represent the largest stumbling block to 

widespread commercialization of CCS. Currently available CO2

capture and compression processes are estimated to 

represent three quarters of the overall CCS costs. 

In general, CO2 capture technologies applicable to 

coal-fired power generation can be categorized into three 

approaches1:

 Pre-combustion systems are designed to separate CO2 and 

H2 in the high-pressure syngas produced at IGCC power 

plants.

 Post-combustion systems are designed to separate CO2

from the flue gas produced by fossil-fuel combustion 

in air.

 Oxy-combustion uses high-purity O2, rather than air, to 

combust coal and therefore produces a highly 

concentrated CO2 stream.

Each of these three carbon capture approaches (precombustion, post-combustion, and oxy-combustion) is 

technologically feasible. However, each results in 

 

1 IPCC, 2005; DOE, 2007.
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increased capital and operating costs and decreased 

electricity output (that is, an energy penalty), with a 

resulting increase in the cost of electricity. The energy 

penalty occurs because the CO2 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 CCS are the costs of capturing and 

compressing CO2. The remaining steps for CCS, pipeline 

transportation and sequestration, are better established. 

Carbon dioxide has been transported via pipelines in 

the U.S. for nearly 40 years. Approximately 50 million 

metric tons of CO2 are transported each year through 3,600 

miles of pipelines. Moreover, a review of the 500 largest 

CO2 point sources in the U.S. shows that 95 percent are 

within 50 miles of a possible geologic 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 Research Institute, Battelle 

Pacific Northwest Division. PNWD-3602. College Park, MD.
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With respect to sequestration, globally, there are at 

least four commercial integrated CCS facilities 

sequestering captured CO2 into deep geologic formations and 

applying a suite of technologies to monitor and verify that 

the CO2 remains sequestered.3These four sites represent 

over 25 years of cumulative experience on safely and 

effectively storing anthropogenic CO2 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 CO2 in deep saline formations, 

oil and gas reservoirs and unmineable coal seams.5 The U.S.

experience with large-scale CO2 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 –

- along with capture and transport -- of large amounts of 

CO2 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. Department of Energy National Energy Technology Laboratory 

(2010). Carbon Sequestration Atlas of the United States and 

Canada, Third Edition.
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It should be noted that the EPA recently finalized two 

rules that aim to protect drinking water and track the 

amount of CO2 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 ensure 

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 protect 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 injected CO2

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 CO2 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 (CO2) Geologic Sequestration 

(GS) Wells, Final Rule, 75 FR 77230 (Dec. 10, 2010).
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Program, which was established under authority of the CAA 

and builds on UIC requirements, provides requirements for 

quantifying the amount of CO2 sequestered by these 

facilities.7 In addition, the EPA recently proposed a rule 

that would conditionally exclude CO2 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 CO2 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 CO2 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 Listing 

of Hazardous Waste: Carbon Dioxide (CO2) Streams in Geologic 

Sequestration Activities, Proposed Rule, 76 FR 48073 (Aug. 8, 

2011).
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(2) Expected reduction in CCS costs. As noted above, 

currently available CO2 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 extensive research development and 

demonstration program that is focused on developing 

advanced technology options that dramatically lower the 

cost of capturing CO2 from fossil-fuel energy plants 

compared to today’s available capture technologies. The 

DOE/NETL estimates 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) plant. 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 electricity for new gasification-based power 

plants.9The large-scale CO2 capture demonstrations that are 

 

9 DOE/NETL Carbon Dioxide Capture and Storage RD&D Roadmap, U.S. 
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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 CO2 from other gases have been in use 

since the 1930s in the natural gas industry and to produce 

food and chemical grade CO2. The advancement of amine-based 

solvents is an example of technology development that has 

improved the cost and performance of CO2 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 CO2 and contains a 

corrosion inhibitor that allows the use 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 Laboratory, 

December 2010.
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corrosion issues. The DOE/NETL and private industry are

continuing to sponsor research on advanced solvents 

(including new classes of amines) to improve the CO2 capture 

performance and reduce costs.

Significant reductions in the cost of CO2 capture would 

be consistent 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 this 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 

observed 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 Effects 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 1990 to 2020,” U.S. EPA, Office of Air and Radiation, April 2011.
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used historical experience curves as the basis for 

estimating future cost trends for four types of new 

electric power plants equipped with CO2 capture systems: PC 

and NGCC plants with post-combustion CO2 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 other energy and 

environmental process technologies and then, by analogy, 

estimated future cost reductions that might be achieved by 

power plants employing CO2 capture. The results of the study 

suggested that total costs of CO2 capture can be expected to 

reduce 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, including overall energy loss in 

power plants, the energy required for CO2 capture, the CO2

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, 188 (2007).
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cost with increased implementation.12

In addition, we note that the Administration’s CCS 

Task Force report recognized that CCS could 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 CO2 capture”, Progress in Energy 

and Combustion Science 35 (2009) 457-480.

13 See Center for Climate and Energy Solutions, “Financial Incentives for CCS” -

http://www.c2es.org/sites/default/modules/usmap/pdf.php?file=8380
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CCS. Several states have recently established requirements 

for CCS, and a number of with CCS have been approved 

and/or are under construction. .

In May 2007, Montana Governor Schweitzer signed House 

Bill 25, adopting a CO2 emissions performance standard for 

electric generating units in the state. House Bill 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 CO2 produced by 

the facility is captured and sequestered.

On January 12, 2009, Illinois Governor Blagojevich 

signed Senate Bill 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 CO2 capture systems, including, in some 

cases, part of the components for coal-based power plant 

applications.
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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 

CO2 per year are captured, whereas at Shady Point 66,000 

tonnes of CO2 per year are captured. The CO2 from both 

plants is subsequently used in the food processing 

industry14.

At the Searles Valley Minerals soda ash plant in 

Trona, CA, approximately 270,000 tonnes of CO2 per year are 

captured from the flue gas of a coal power plant via amine 

scrubbing and used for the carbonation of brine in the 

process of producing soda ash.

15

A pre-combustion Rectisol® system is used for CO2

capture at the Dakota Gasification Company’s synthetic 

natural gas production plant located in North Dakota, which 

is designed to remove approximately 1.6 million tonnes of 

CO2 per year from the synthesis gas. The CO2 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.
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Weyburn oilfield in Saskatchewan, Canada. 

In September 2009, American Electric Power Co. (AEP)

began a pilot-scale CCS demonstration at its 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 CO2 capture technology on a 20 MWe 

portion, or “slipstream”, of the plant’s exhaust flue 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 CO2 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 

CO2 at purity of greater than 99 percent, with energy 

penalties 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 from the DOE, had planned to 

expand the slipstream demonstration to a commercial scale, 

fully integrated demonstration at the Mountaineer facility. 
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The commercial-scale system was designed to capture at 

least 90 percent of the CO2 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 plans to advance CO2 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 CO2 per 

year 

In June 2011, Mitsubishi Heavy Industries, an 

equipment manufacturer, announced 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 CO2 annually (500 tons per day) at a CO2 capture 

rate of over 90 percent. The captured CO2 will be 
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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 precombustion carbon capture to reduce CO2 emissions by 65

percent. Operation is expected to begin in 2014. The CO2

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 CO2, 

which is approximately 3 million tonnes annually. The 

captured CO2 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 
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CO2 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 projects 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-andevents/press-releases .
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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.