Carbon Capture and Sequestration: Research, 

Development, and Demonstration at the U.S. 

Department of Energy 

Peter Folger 

Specialist in Energy and Natural Resources Policy 

February 10, 2014 

Congressional Research Service 

7-5700 

www.crs.gov 

R42496 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 

Summary 

On September 20, 2013, the U.S. Environmental Protection Agency (EPA) re-proposed standards 

for carbon dioxide (CO2) emissions from new fossil-fueled power plants. On January 8, 2014, 

EPA published the re-proposed rule in the Federal Register, triggering the start of a 60-day public 

comment period. The proposed rule places a new focus on whether the U.S. Department of 

Energy’s (DOE’s) CCS research, development, and demonstration (RD&D) program will achieve 

its vision of developing an advanced CCS technology portfolio ready by 2020 for large-scale 

CCS deployment. 

As re-proposed, the standards would limit emissions of CO2 to no more than 1,100 pounds per 

megawatt-hour (lbs/Mwh) of production from new coal-fired power plants and between 1,000 

and 1,100 lbs/Mwh (depending on size of the plant) for new natural gas-fired plants. EPA 

proposed the standard under Section 111 of the Clean Air Act. According to EPA, new natural 

gas-fired stationary power plants should be able to meet the proposed standards without 

additional cost and the need for add-on control technology. However, new coal-fired plants only 

would be able to meet the standards by installing carbon capture and sequestration (CCS) 

technology. The re-proposed rule has sparked increased scrutiny of the future of CCS as a viable 

technology for reducing CO2 emissions from coal-fired power plants. 

Congress appropriated $3.4 billion from the American Recovery and Reinvestment Act (Recovery 

Act) for CCS RD&D at DOE’s Office of Fossil Energy in addition to annual appropriations for 

CCS. The large influx of funding for industrial-scale CCS projects was intended to accelerate 

development and deployment of CCS in the United States. Since enactment of the Recovery Act, 

DOE has shifted its RD&D emphasis to the demonstration phase of carbon capture technology. 

To date, however, there are no commercial ventures in the United States that capture, transport, 

and inject industrial-scale quantities of CO2 solely for the purposes of carbon sequestration. 

The success of DOE CCS demonstration projects will likely influence the future outlook for 

widespread deployment of CCS technologies as a strategy for preventing large quantities of CO2

from reaching the atmosphere while U.S. power plants continue to burn fossil fuels, mainly coal. 

One project, the Kemper County Facility, has received $270 million from DOE under its Clean 

Coal Power Initiative Round 2 program, and is slated to begin commercial operation in late 2014. 

The 583 megawatt capacity facility anticipates capturing 65% of its CO2 emissions, making it 

equivalent to a new natural gas-fired combined cycle power plant. Cost overruns at the Kemper 

Plant, however, have raised questions over the relative value of environmental benefits due to 

CCS technology compared to construction costs of the facility and its effect on ratepayers. 

Given the pending EPA rule, congressional interest in the future of coal as a domestic energy 

source appears directly linked to the future of CCS. Following the September 20, 2013, reproposal of the rule the debate has been mixed as to whether the rule would spur development 

and deployment of CCS for new coal-fired power plants or have the opposite effect. Several bills 

introduced in the House and Senate, such as H.R. 3826 and S. 1905, directly address EPA’s 

authority to issue regulations curtailing CO2 emissions from coal-fired power plants. 

Congressional oversight of the CCS RD&D program could help inform decisions about the level 

of support for the program and help Congress gauge whether it is on track to meet its goals. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 

Contents 

Introduction ...................................................................................................................................... 1

EPA Proposed Rule: Limiting CO2 Emissions from Power Plants .................................................. 2

New Power Plants ...................................................................................................................... 2

Existing Power Plants ................................................................................................................ 3

Implications for CCS Research, Development, and Deployment ............................................. 3

The Natural Gas Alternative? .............................................................................................. 3

Legislation ....................................................................................................................................... 4

113th Congress ........................................................................................................................... 5

112th Congress ........................................................................................................................... 5

111th Congress............................................................................................................................ 5

CCS Research, Development, and Demonstration: Overall Goals .................................................. 6

Program Areas ........................................................................................................................... 7

First Full-Scale Project? The Kemper County Energy Facility ............................................... 10

Recovery Act Funding for CCS Projects: A Lynchpin for Success?.............................................. 11

CCS Demonstrations: CCPI, ICCS, and FutureGen 2.0 .......................................................... 12

Clean Coal Power Initiative .............................................................................................. 12

Industrial Carbon Capture and Storage Projects ............................................................... 16

FutureGen—A Special Case? ............................................................................................ 18

Geologic Sequestration/Storage: DOE RD&D for the Last Step in CCS ...................................... 21

Brief History of DOE Geological Sequestration/Storage Activities ........................................ 21

Current Status and Challenges to Carbon Sequestration/Storage ............................................ 23

Outlook .......................................................................................................................................... 24

Figures 

Figure 1. Typical Trend in Cost Estimates for a New Technology As It Develops 

from a Research Concept to Commercial Maturity .................................................................... 10

Tables 

Table 1. DOE Carbon Capture and Storage Research, Development, and Demonstration 

Program Areas .............................................................................................................................. 8

Table 2. DOE CCS Demonstration Round 3 Projects .................................................................... 13

Table 3. DOE Industrial Carbon Capture and Storage (ICCS) Projects ........................................ 17

Table 4. Regional Carbon Sequestration Partnerships ................................................................... 22

Contacts 

Author Contact Information........................................................................................................... 25
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 1 

Introduction 

Carbon capture and sequestration (or storage)—known as CCS—is a physical process that 

involves capturing manmade carbon dioxide (CO2) at its source and storing it before its release to 

the atmosphere. CCS could reduce the amount of CO2 emitted to the atmosphere while allowing 

the continued use of fossil fuels at power plants and other large, industrial facilities. An integrated 

CCS system would include three main steps: (1) capturing CO2 at its source and separating it 

from other gases; (2) purifying, compressing, and transporting the captured CO2 to the 

sequestration site; and (3) injecting the CO2 into subsurface geological reservoirs. Following its 

injection into a subsurface reservoir, the CO2 would need to be monitored for leakage and to 

verify that it remains in the target geological reservoir. Once injection operations cease, a 

responsible party would need to take title to the injected CO2 and ensure that it stays underground 

in perpetuity. 

The U.S. Department of Energy (DOE) has pursued research and development of aspects of the 

three main steps leading to an integrated CCS system since 1997.1

 Congress has appropriated 

approximately $6 billion in total since FY2008 for CCS research, development, and 

demonstration (RD&D) at DOE’s Office of Fossil Energy: approximately $3 billion in total 

annual appropriations (including FY2014), and $3.4 billion from the American Recovery and 

Reinvestment Act (P.L. 111-5, enacted February 17, 2009, hereinafter referred to as the Recovery 

Act). 

The large and rapid influx of funding for industrial-scale CCS projects from the Recovery Act 

was intended to accelerate development and demonstration of CCS in the United States. The 

Recovery Act funding also was likely intended to help DOE achieve its RD&D goals as outlined 

in the department’s 2010 RD&D CCS Roadmap.

2

 (In part, the roadmap was intended to lay out a 

path for rapid technological development of CCS so that the United States would continue to use 

fossil fuels.) However, the future deployment of CCS may take a different course if the major 

components of the DOE program follow a path similar to DOE’s FutureGen project, which has 

experienced delays and multiple changes of scope and design since its inception in 2003.3

 

This report aims to provide a snapshot of the DOE CCS program, including its current funding 

levels, together with some discussion of the program’s achievements and prospects for success in 

meeting its stated goals. Other CRS reports provide substantial detail on the technological and 

policy aspects of CCS.4

 

 

1

 U.S. Department of Energy, National Energy Technology Laboratory, Carbon Sequestration Program: Technology 

Program Plan, Enhancing the Success of Carbon Capture and Storage Technologies, February 2011, p. 10, 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/2011_Sequestration_Program_Plan.pdf. 

2

 U.S. Department of Energy, National Energy Technology Laboratory, DOE/NETL Carbon Dioxide Capture and 

Storage RD&D Roadmap, December 2010. Hereinafter referred to as the DOE 2010 CCS Roadmap. See 

http://www.netl.doe.gov/File%20Library/Research/Carbon%20Seq/Reference%20Shelf/CCSRoadmap.pdf. 

3

 As originally conceived in 2003, FutureGen would have been a 10-year project to build a coal-fired power plant that 

would integrate carbon sequestration and hydrogen production while producing 275 megawatts of electricity, enough to 

power about 150,000 average U.S. homes. The plant would have been a coal-gasification facility and would have 

produced and sequestered between 1 million and 2 million tons of CO2 annually. FutureGen 2.0 differs from the 

original concept for the plant, because it would retrofit an existing power plant in Meredosia, IL, with oxy-combustion 

technology, and is funded largely by appropriations made available by the Recovery Act. See CRS Report R43028, The 

FutureGen Carbon Capture and Sequestration Project: A Brief History and Issues for Congress, by Peter Folger 

4

 See, for example, CRS Report R42532, Carbon Capture and Sequestration (CCS): A Primer; CRS Report R41325, 

(continued...) 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 2 

EPA Proposed Rule: Limiting CO2 Emissions from 

Power Plants5

New Power Plants 

On September 20, 2013, the U.S. Environmental Protection Agency (EPA) re-proposed a standard 

that would limit emissions of carbon dioxide (CO2) from new fossil-fueled power plants. As reproposed, the rule would limit emissions to no more than 1,100 pounds per megawatt-hour of 

electric generation from new coal-fired power plants and between 1,000 and 1,100 pounds per 

megawatt-hour (depending on size of the plant) for new natural gas-fired plants. EPA proposed 

the standard under Section 111 of the Clean Air Act. According to EPA, new natural gas-fired 

stationary power plants should be able to meet the proposed standard without additional cost and 

the need for add-on control technology. However, the only technical way for new coal-fired plants 

to meet the standard would be to install carbon capture and sequestration (CCS) technology to 

capture about 40% of the CO2 they typically produce. The proposed standard allows for a sevenyear compliance period for coal-fired plants but would demand a more stringent standard for 

those plants that comply over seven years; CO2 emissions for these plants would be limited to an 

average of 1,000-1,050 pounds per megawatt-hour.6

 

On January 8, 2014, EPA published the re-proposed rule in the Federal Register.

7

 Publishing in 

the Federal Register triggers the start of a 60-day public comment period: Comments will be 

accepted until March 10, 2014. The 2012 proposal generated more than 2.5 million comments, 

which prompted, in part, the September 20, 2013, re-proposal. Promulgation of the final rule 

could be expected sometime after the public comment period ends and EPA evaluates the 

comments. 

The prospects for building new coal-fired electricity generating plants depend on many factors, 

such as costs of competing fuel sources (e.g., natural gas), electricity demand, regulatory costs, 

infrastructure (including rail) and electric grid development, and others. However, the EPA 

proposed rule clearly identifies CCS as the essential technology required if new coal-fired power 

plants are to be built in the United States.8

 The re-proposed standard places a new focus on DOE’s 

CCS RD&D program—whether it will achieve its vision of “having an advanced CCS technology 

portfolio ready by 2020 for large-scale CCS demonstration that provides for the safe, costeffective carbon management that will meet our Nation’s goals for reducing [greenhouse gas] 

emissions.”9

 

(...continued) 

Carbon Capture: A Technology Assessment. 

5

 For a fuller discussion of the proposed rule and EPA standards for greenhouse gas emissions from power plants, see 

CRS Report R43127, EPA Standards for Greenhouse Gas Emissions from Power Plants: Many Questions, Some 

Answers, by James E. McCarthy. 

6

 The proposal and background information is available at http://www2.epa.gov/carbon-pollution-standards/2013-

proposed-carbon-pollution-standard-new-power-plants. 

7

 Environmental Protection Agency, “Standards of Performance for Greenhouse Gas Emissions From New Stationary 

Sources: Electric Utility Generating Units,” 79 Federal Register 1429, January 8, 2014. 

8

 Ibid. 

9

 DOE 2010 CCS Roadmap, p. 3. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 3 

Existing Power Plants 

The September 2013 re-proposed rule would address only new power plants. However, Section 

111 of the Clean Air Act requires that EPA develop guidelines for greenhouse gas emissions for 

existing plants whenever it promulgates standards for new power plants. In his June 25, 2013, 

memorandum, President Obama directed the EPA to issue proposed guidelines for existing plants 

by June 1, 2014, and to issue final guidelines a year later.10

Implications for CCS Research, Development, and Deployment 

Congress has appropriated funding for DOE to pursue CCS research and development since 1997 

and signaled its interest in CCS technology by awarding $3.4 billion from the Recovery Act to 

CCS programs at DOE. Given the pending EPA rule, congressional interest in the future of coal 

as a domestic energy source appears directly linked to the future of CCS. Following the 

September 20, 2013, re-proposal of the rule, the debate has been mixed as to whether the rule 

would spur development and deployment of CCS for new coal-fired power plants or have the 

opposite effect. Multiple analyses indicate that there will be retirements of U.S. coal-fired 

capacity; however, virtually all analyses agree that coal will continue to play a substantial role in 

electricity generation for decades. How many retirements would take place and the role of EPA 

regulations in causing them are matters of dispute.11

Since the September 2013 re-proposal, the argument over the rule has focused, in part, on 

whether CCS is the best system of emissions reduction (BSER) for coal plants and whether it has 

been “adequately demonstrated” as such as required under the Clean Air Act. In its re-proposed 

rule, EPA cites the “existence and apparent ongoing viability” of several ongoing CCS 

demonstration projects as examples that justify a separate determination of BSER for coal-fired 

plants and integrated gasification combined-cycle plants. (The second BSER determination is for 

gas-fired power plants.)12 The EPA noted that these projects had reached advanced stages of 

construction and development, “which suggests that proposing a separate standard for coal-fired 

units is appropriate.” 

The Natural Gas Alternative? 

The huge increases in the U.S. domestic supply of natural gas in recent years, due largely to the 

exploitation of unconventional shale gas reservoirs through the use of hydraulic fracturing, has 

also led to a shift to natural gas for electricity production.13 The shift appears to be largely due to 

the cheaper and increasingly abundant fuel—natural gas—compared to coal for electricity 

 

10 Office of the Press Secretary, The White House, “Power Sector Carbon Pollution Standards,” Memorandum for the 

Administrator of the Environmental Protection Agency, June 25, 2013, http://www.whitehouse.gov/the-press-office/

2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards. 

11 For a detailed discussion of the EPA’s regulation of coal, see CRS Report R41914, EPA’s Regulation of Coal-Fired 

Power: Is a “Train Wreck” Coming?, by James E. McCarthy and Claudia Copeland. 

12 The projects cited in the re-proposed rule are the Southern Company Kemper County Energy Facility, the SaskPower 

Boundary Dam CCS project, the Summit Power Texas Clean Energy Project, and the Hydrogen Energy California 

Project. The Boundary Dam project is a Canadian venture; the other three projects are in the United States and are 

receiving funding from DOE. 

13 For a detailed discussion of how natural gas is affecting electric power generation, see CRS Report R42814, Natural 

Gas in the U.S. Economy: Opportunities for Growth , by Robert Pirog and Michael Ratner. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 4 

production. The EPA re-proposed rule, discussed above, noted that “power companies often 

choose the lowest cost form of generation when determining what type of new generation to 

build. Based on [Energy Information Administration] modeling and utility [Integrated Resource 

Plans], there appears to be a general acceptance that the lowest cost form of new power 

generations is [natural gas combined-cycle].” Cheap gas, due to the rapid increase in the domestic 

natural gas supply as an alternative to coal, in combination with regulations that curtail CO2 

emissions may lead electric power producers to invest in natural gas-fired plants, which emit 

approximately half the amount of CO2 per unit of electricity produced compared to coal-fired 

plants. Regulations and abundant cheap gas may raise questions about the rationale for funding 

CCS demonstration projects like FutureGen. 

Alternatively, and despite increasingly abundant domestic natural gas supplies, EPA regulations 

could provide the necessary incentives for the industry to accelerate CCS development and 

deployment for coal-fired power plants. As part of its re-proposed ruling, EPA cites technology as 

one of four factors that it considers in making a BSER determination.14 Specifically, EPA stated 

that it “considers whether the system promotes the implementation and further development of 

technology,” in this case referring to CCS technology. It appears that EPA asserts that its rule 

would likely promote CCS development and deployment rather than hinder it. Those arguing 

against the re-proposed rule do so on the basis that CCS technology has not been adequately 

demonstrated, and that it violates provisions in P.L. 109-58, the Energy Policy Act of 2005, that 

prohibit EPA from setting a performance standard based on the use of technology from certain 

DOE-funded projects, such as the three projects cited in the EPA re-proposal, among other 

reasons.15 

Legislation 

Although DOE has pursued aspects of CCS RD&D since 1997, the Energy Policy Act of 2005 

(P.L. 109-58) provided a 10-year authorization for the basic framework of CCS research and 

development at DOE.16 The Energy Independence and Security Act of 2007 (EISA, P.L. 110-140) 

amended the Energy Policy Act of 2005 to include, among other provisions, authorization for 

seven large-scale CCS demonstration projects (in addition to FutureGen) that would integrate the 

carbon capture, transportation, and sequestration steps.17 (Large-scale demonstration programs 

and their potential significance are discussed below.) It can be argued that, since enactment of 

EISA, the focus and funding within the CCS RD&D program has shifted toward large-scale 

capture technology development through these and other demonstration projects. 

In addition to the annual appropriations provided for CCS RD&D, the Recovery Act (P.L. 111-5) 

has been the most significant legislation that promotes and supports federal CCS RD&D program 

activities since passage of EISA. As discussed below, $3.4 billion in funding from the Recovery 

 

14 The other three are feasibility, costs, and size of emission reductions. 

15 See for example, the November 15, 2013, letter to EPA Administrator Gina McCarthy from Representative Fred 

Upton, chair of the House Committee on Energy and Commerce, http://www.eenews.net/assets/2013/11/22/

document_daily_03.pdf; and the December 19, 2013, letter to Administrator McCarthy from Representative Lamar 

Smith, chair of the House Committee on Science, Space, and Technology, http://science.house.gov/sites/

republicans.science.house.gov/files/documents/Letters/121913_mccarthy.pdf. 

16 P.L. 109-58, Title IX, Subtitle F, §963; 42 U.S.C. 16293. 

17 P.L. 110-140, Title VII, Subtitles A and B. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 5 

Act was intended to expand and accelerate the commercial deployment of CCS technologies to 

allow for commercial-scale demonstration in both new and retrofitted power plants and industrial 

facilities by 2020. 

113th Congress 

As introduced on January 9, 2014, H.R. 3826, the Electricity Security and Affordability Act, 

would essentially set requirements EPA must meet before the agency could issue greenhouse gas 

emission regulations under Section 111 of the Clean Air Act, such as the EPA re-proposed rule 

discussed above. On January 14, 2014, the Energy and Power Subcommittee, House Energy and 

Commerce Committee, voted to report the bill. Much of the discussion during the bill’s markup 

centered on whether CCS was an adequately demonstrated technology to meet the requirements 

of the Clean Air Act. On January 28, 2014, the full committee voted to report the bill. Companion 

legislation, S. 1905, was introduced on January 9, 2014, and referred to the Senate Committee on 

Environment and Public Works. 

A bill introduced on May 23, 2013, H.R. 2127, would prohibit the EPA from finalizing any rule 

limiting the emission of CO2 from any existing or new source that is a fossil fuel-fired electric 

utility generating unit unless and until CCS becomes technologically and economically feasible. 

Other bills that target the EPA’s proposed rule on limiting CO2 emissions from new power plants 

were introduced shortly before and after the September 20, 2013, rule was proposed, including 

H.J.Res. 64, H.R. 3140, S. 1514, and others. 

112th Congress 

In the 112th Congress, a few bills were introduced that would have addressed aspects of CCS 

RD&D. The Department of Energy Carbon Capture and Sequestration Program Amendments Act 

of 2011 (S. 699) would have provided federal indemnification of up to $10 billion per project to 

early adopters of CCS technology (large CCS demonstration projects).18 The New Manhattan 

Project for Energy Independence (H.R. 301) would have created a system of grants and prizes for 

a variety of technologies, including CCS, that would contribute to reducing U.S. dependence on 

foreign sources of energy. Other bills introduced would have provided tax incentives for the use 

of CO2 in enhanced oil recovery (S. 1321), or would have eliminated the minimum capture 

requirement for the CO2 sequestration tax credit (H.R. 1023). Other bills were also introduced 

that would have affected other aspects of CCS RD&D financing, such as loan guarantees. None 

of the bills introduced in the 112th Congress affecting federal CCS RD&D, other than the 

continuing resolution (CR), was enacted. 

111th Congress 

In the 111th Congress, two bills that would have authorized a national cap-and-trade system for 

limiting the emission of greenhouse gases (H.R. 2454 and S. 1733) also would have created 

programs aimed at accelerating the commercial availability of CCS. The programs would have 

generated funding from a surcharge on electricity delivered from the combustion of fossil fuels—

 

18 Among other provisions, the bill would also have amended EISA to expand the number of large CCS demonstration 

projects from 7 to 10. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 6 

approximately $1 billion per year—and made the funding available for grants, contracts, and 

financial assistance to eligible entities seeking to develop CCS technology. Another source of 

funding in the bills was to come from a program that would distribute emission allowances to 

“early movers,” entities that installed CCS technology on up to a total of 20 gigawatts of 

generating capacity. The House of Representatives passed H.R. 2454, but neither bill was 

enacted. 

CCS Research, Development, and Demonstration: 

Overall Goals 

The U.S. Department of Energy states that the mission for the DOE Office of Fossil Energy is “to 

ensure the availability of ultra-clean (near-zero emissions), abundant, low-cost domestic energy 

from coal to fuel economic prosperity, strengthen energy security, and enhance environmental 

quality.”19 Over the past several years, the DOE Fossil Energy Research and Development 

Program has increasingly shifted activities performed under its Coal Program toward 

emphasizing CCS as the main focus.20 The Coal Program represented 69% of total Fossil Energy 

Research and Development appropriations in FY2012 and in FY2013,21 and represents nearly 

70% in the FY2014 appropriation,22 indicating that CCS has come to dominate coal R&D at 

DOE. This reflects DOE’s view that “there is a growing consensus that steps must be taken to 

significantly reduce [greenhouse gas] emissions from energy use throughout the world at a pace 

consistent to stabilize atmospheric concentrations of CO2, and that CCS is a promising option for 

addressing this challenge.”23

DOE also acknowledges that the cost of deploying currently available CCS technologies is very 

high, and that to be effective as a technology for mitigating greenhouse gas emissions from power 

plants, the costs for CCS must be reduced. For example, in 2010 DOE stated that the cost of 

deploying available CCS post-combustion technology on a supercritical pulverized coal-fired 

power plant would increase the cost of electricity by 80%.24 The challenge of reducing the costs 

of CCS technology is difficult to quantify, in part because there are no examples of currently 

operating commercial-scale coal-fired power plants equipped with CCS. Nor is it easy to predict 

when lower-cost CCS technology will be available for widespread deployment in the United 

States. Nevertheless, DOE observes that “the United States can no longer afford the luxury of 

conventional long-lead times for RD&D to bear results.”25 Thus the coal RD&D program is 

 

19 DOE 2010 CCS Roadmap, p. 2. 

20 The Coal Program contains CCS RD&D activities, and is within DOE’s Office of Fossil Energy, Fossil Energy 

Research and Development, as listed in DOE detailed budget justifications for each fiscal year. See, for example, U.S. 

Department of Energy, FY2014 Congressional Budget Request, volume 3, Fossil Energy Research and Development, 

http://energy.gov/sites/prod/files/2013/04/f0/Volume3_1.pdf. The percentage of funding allocated to the Coal Program 

is calculated based on the subtotal for Fossil Energy Research and Development prior to rescission of prior year 

balances, which were $187 million for FY2012 and $42 million for FY2013, respectively. 

21 U.S. Department of Energy, FY2013 Congressional Budget Request, volume 3, Fossil Energy Research and 

Development, p. 411. 

22 FY2014 Joint Explanatory Statement in the Congressional Record, January 15, 2014, and P.L. 113-76. 

23 DOE 2010 CCS Roadmap, p. 3. 

24 DOE 2010 CCS Roadmap, p. 3. 

25 DOE 2010 CCS Roadmap, p. 3. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 7 

focused on achieving results that would allow for an advanced CCS technology portfolio to be 

ready by 2020 for large-scale demonstration. 

The following section describes the components of the CCS activities within DOE’s coal R&D 

program and their funding history since FY2012. This report focuses on this time period because 

during that time DOE obligated Recovery Act funding for its CCS programs, greatly expanding 

the CCS R&D portfolio. This was expected to accelerate the transition of CCS technology to 

industry for deployment and commercialization.26 In addition, one remaining active project in the 

Clean Coal Power Initiative (CCPI) program that received funding in Round 2, prior to enactment 

of the Recovery Act—the Kemper County Energy Facility—is also discussed. 

Program Areas 

The 2010 RD&D CCS Roadmap described 10 different program areas pursued by DOE’s Coal 

Program within the Office of Fossil Energy: (1) Innovations for Existing Plants (IEP); (2) 

Advanced Integrated Gasification Combined Cycle (IGCC); (3) Advanced Turbines; (4) Carbon 

Sequestration; (5) Solid State Energy Conversion Fuel Cells; (6) Fuels; (7) Advanced Research; 

(8) Clean Coal Power Initiative (CCPI); (9) FutureGen; and (10) Industrial Carbon Capture and 

Storage Projects (ICCS).27 

DOE changed the program structure after FY2010, renaming and consolidating program areas. 

The program areas are divided into two main categories: (1) CCS Demonstration Programs, and 

(2) Carbon Capture and Storage, and Power Systems. Table 1 shows the current program 

structure and indicates which programs received Recovery Act funding. In its FY2014 Budget 

Justification, DOE stated that the mission of these program areas is 

to support secure, affordable, and environmentally acceptable near-zero emissions fossil energy 

technologies. This will be accomplished via research, development, and demonstration to 

improve the performance of advanced CCS technologies. Commercial availability of CCS 

technologies will provide an option to use fossil fuel resources to provide provide energy and 

meet the President’s climate goals.28 

Some programs are directly focused on one or more of the three steps of CCS: capture, 

transportation, and storage. For example, the carbon capture program supports R&D on postcombustion, pre-combustion, and natural gas capture. The carbon storage program supports the 

regional carbon sequestration partnerships, geological storage technologies, and other aspects of 

permanently sequestering CO2 underground. In contrast, FutureGen from the outset was 

envisioned as combining all three steps: a zero-emission fossil fuel plant that would capture its 

emissions and sequester them in a geologic reservoir. 

 

26 DOE 2010 CCS Roadmap, p. 2. 

27 DOE 2010 CCS Roadmap, p. 11. 

28 U.S. Department of Energy, FY2014 Congressional Budget Request, volume 3, Fossil Energy Research and 

Development, p. FE-13. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 8 

Table 1. DOE Carbon Capture and Storage Research, Development, and 

Demonstration Program Areas 

(funding in $ thousands, FY2012-FY2014, including Recovery Act funding) 

Fossil Energy 

Research and 

Development 

Coal Program 

Areas Program 

Recovery 

Act FY2012 

FY2013 

(annualized 

CR)a

FY2014 

(Request) 

P.L. 113-

76 

CCS 

Demonstrations 

FutureGen 2.0 1,000,000 0 0 0 0 

 Clean Coal 

Power Initiative 

(CCPI) 

800,000 0 0 0 0 

 Industrial Carbon 

Capture and 

Storage Projects 

(ICCS) 

1,520,000 0 0 0 0 

 Site 

Characterization, 

Training, 

Program 

Direction 

80,000 0 0 0 0 

Carbon Capture 

and Storage, and 

Power Systems 

Carbon Capture — 66,986 65,600 112,000 92,000 

 Advanced Energy 

Systems 

— 97,169 95,200 48,000 99,500 

 Carbon Storage — 112,208 109,900 61,095 108,900 

 Cross Cutting 

Research 

— 47,946 46,800 20,525 41,900 

 NETL Coal 

Research and 

Development 

 35,011 33,300 35,011 50,000 

 3,400,000 359,320 350,800 276,631 392,300 

Source: U.S. Department of Energy, FY2013 Congressional Budget Request, volume 3, Fossil Energy Research and 

Development, http://energy.gov/sites/prod/files/2013/04/f0/Volume3_1.pdf. U.S. Department of Energy, Carbon 

Sequestration, Recovery Act, http://www.fe.doe.gov/recovery/index.html; U.S. Department of Energy, FY2014. 

Congressional Budget Request, volume 3, Fossil Energy Research and Development, http://energy.gov/sites/prod/

files/2013/04/f0/Volume3_1.pdf; FY2014 Joint Explanatory Statement in the Congressional Record, January 15, 

2014, and P.L. 113-76. 

a. According to DOE, the FY2013 column amounts reflect the continuing resolution (CR, P.L. 112-175) levels 

annualized to a full year. Figures reflect the March 1, 2013, sequester of funds under P.L. 112-25. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 9 

Within the CCS Demonstration Program Area, RD&D is also divided among different industrial 

sectors. The Clean Coal Power Initiative (CCPI) program area originally provided federal support 

to new coal technologies that helped power plants cut sulfur, nitrogen, and mercury pollutants. As 

CCS became the focus of coal RD&D, the CCPI program shifted to reducing greenhouse gas 

emissions by boosting plant efficiencies and capturing CO2.

29 In contrast, the ICCS program area 

demonstrates carbon capture technology for the non-power plant industrial sector.30 Both these 

program areas focus on the demonstration component of RD&D, and account for $2.3 billion of 

the $3.4 billion appropriated for CCS RD&D in the Recovery Act in FY2009. From the budgetary 

perspective, the Recovery Act funding shifted the emphasis of CCS RD&D to large, industrial 

demonstration projects for carbon capture. The CCPI and ICCS program areas are discussed in 

more detail below. 

This shift in emphasis to the demonstration phase of carbon capture technology is not surprising, 

and appears to heed recommendations from many experts who have called for large, industrialscale carbon capture demonstration projects.31 Primarily, the call for large-scale CCS 

demonstration projects that capture 1 million metric tons or more of CO2 per year reflects the 

need to reduce the additional costs to the power plant or industrial facility associated with 

capturing the CO2 before it is emitted to the atmosphere. The capture component of CCS is the 

costliest component, according to most experts.32 The higher estimated costs to build and operate 

power plants with CCS compared to plants without CCS, and the uncertainty in cost estimates, 

results in part from a dearth of information about outstanding technical questions in carbon 

capture technology at the industrial scale.33 

In comparative studies of cost estimates for other environmental technologies, such as for power 

plant scrubbers that remove sulfur and nitrogen compounds from power plant emissions (SO2 and 

NOx), some experts note that the farther away a technology is from commercial reality, the more 

uncertain is its estimated cost. At the beginning of the RD&D process, initial cost estimates could 

be low, but could typically increase through the demonstration phase before decreasing after 

successful deployment and commercialization. Figure 1 shows a cost estimate curve of this type. 

 

29 Ibid., p. FE-16. 

30 DOE 2010 CCS Roadmap, p. 12. 

31 See, for example, the presentations given by Edward Rubin of Carnegie Mellon University, Howard Herzog of the 

Massachusetts Institute of Technology, and Jeff Phillips of the Electric Power Research Institute, at the CRS seminar 

Capturing Carbon for Climate Control: What’s in the Toolbox and What’s Missing, November 18, 2009. (Presentations 

available from Peter Folger at 7-1517.) Rubin stated that at least 10 full-scale demonstration projects would be needed 

to establish the reliability and true cost of CCS in power plant applications. Herzog also called for at least 10 

demonstration plants worldwide that capture and sequester a million metric tons of CO2 per year. In his presentation, 

Phillips stated that large-scale demonstrations are critical to building confidence among power plant owners. 

32 For example, an MIT report estimated that the costs of capture could be 80% or more of the total CCS costs. John 

Deutsch et al., The Future of Coal, Massachusetts Institute of Technology, An Interdisciplinary MIT Study, 2007, 

Executive Summary, p. xi. 

33 The Future of Coal, p. 97. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 10 

Figure 1. Typical Trend in Cost Estimates for a New Technology As It Develops 

from a Research Concept to Commercial Maturity 

Research Research Development Demonstration Deployment Mature Technology Development Demonstration Deployment Mature Technology

Time or Cumulative Capacity

Capital Cost per Unit of Capacity

Research Research Development Demonstration Deployment Mature Technology Development Demonstration Deployment Mature Technology

Time or Cumulative Capacity

Capital Cost per Unit of Capacity

Source: Adapted from S. Dalton, “CO2 Capture at Coal Fired Power Plants—Status and Outlook,” 9th

International Conference on Greenhouse Gas Control Technologies, Washington, DC, November, 16-20, 2008. 

Deploying commercial-scale CCS demonstration projects—an emphasis within the DOE CCS 

RD&D program—would therefore provide cost estimates closer to operational conditions rather 

than laboratory- or pilot-plant-scale projects. In the case of SO2 and NOx scrubbers, efforts 

typically took two decades or more to bring new concepts (such as combined SO2 and NOx 

capture systems) to the commercial stage. As Figure 1 indicates, costs for new technologies tend 

to fall over time with successful deployment and commercialization. It would be reasonable to 

expect a similar trend for CO2 capture costs if the technologies become widely deployed.34

First Full-Scale Project? The Kemper County Energy Facility 

In a fact sheet accompanying the proposed rule limiting emissions of CO2 from new coal-fired 

power plants, the EPA asserts that CCS technology is currently feasible and refers to a coalgasification project that is over 75% complete: the Kemper County Project. DOE awarded 

Southern Company Services a cooperative agreement under the CCPI Round 2 program, prior to 

enactment of the Recovery Act and the CCPI Round 3 awards, to develop technology at the 

Kemper County Energy Facility in Kemper County, Mississippi. The $270 million award was 

aimed to provide direct financial support for the development and deployment of a gasification 

technology called Transport Integrated Gasification (TRIGTM).35 

The Kemper County Project is an integrated gasification combined-cycle (IGCC)36 power plant 

that will be owned and operated by Mississippi Power Company, a subsidiary of Southern 

 

34 For a fuller discussion of the relationship between costs of developing technologies analogous to CCS, such as SO2

and NOx scrubbers, see CRS Report R41325, Carbon Capture: A Technology Assessment, by Peter Folger. 35 NETL Fact Sheet, “Demonstration of a Coal-Based Transport Gasifier,” Fact Sheet NT42391, March 2013, 

http://www.netl.doe.gov/publications/factsheets/project/NT42391.pdf. 

36 For more information on IGCC power plants and CCS, see CRS Report R41325, Carbon Capture: A Technology 

Assessment, by Peter Folger. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 11 

Company, and which will use lignite as a fuel source. The plant is expected to have an estimated 

peak net output capability of 583 megawatts, and is designed to capture 65% of the total CO2

emissions released from the plant.37 According to DOE, this would make the CO2 emissions from 

the Kemper Project comparable to a natural gas-fired combined cycle power plant, and would 

therefore emit less than the 1,100 pounds per MWh limit as required by the new EPA proposed 

rule. The estimated 3 million tons of CO2 captured each year from the plant would be transported 

via newly constructed pipeline for use in enhanced oil recovery operations at nearby depleted oil 

fields in Mississippi. Commercial operation of the Kemper County Project is expected to begin in 

2014, according to Southern Company.38

The $270 million award under Round 2 of the CCPI program represents less than 10% of the 

overall cost to build the plant, which is reported to be approximately $3 billion, according to a 

March 2013 DOE fact sheet.39 However, in April 2013 the company announced that capital costs 

would be closer to $3.4 billion, approximately $1 billion higher than original cost estimates for 

the plant.40 In December 2013, Mississippi Power released documents indicating that the project 

was on schedule to begin operations in the last quarter of 2014, but that the total cost for the 

plant, including the lignite mine, CO2 pipeline, land purchase, and all the other components of 

the full project, was approximately $5 billion.41

It is likely that the plant will attract increased scrutiny in the wake of the EPA proposed rule on 

CO2 emissions, and its cost overruns evaluated against the promised environmental benefits due 

to CCS technology.42 As Figure 1 shows above, costs for technologies tend to peak for projects in 

the demonstration phase of development, such as the Kemper County Project. What the cost 

curve will look like, namely, how fast costs will decline and over what time period, is an open 

question and will likely depend on if and how quickly CCS technology is deployed on new and 

existing power plants. 

Recovery Act Funding for CCS Projects: A Lynchpin 

for Success? 

The bulk of Recovery Act funds for CCS ($3.32 billion, or 98%) was directed to three 

subprograms organized under the CCS Demonstrations Programs: the Clean Coal Power 

Initiative (CCPI), Industrial Carbon Capture and Storage projects (ICCS), and FutureGen (Table 

 

37 NETL Fact Sheet, “Demonstration of a Coal-Based Transport Gasifier,” Fact Sheet NT42391, March 2013, 

http://www.netl.doe.gov/publications/factsheets/project/NT42391.pdf. 

38 Mississippi Power, A Southern Company, “Kemper County Energy Facility, Kemper Timeline,” 

http://www.mississippipower.com/kemper/project-timeline.asp. 

39 NETL Fact Sheet, “Demonstration of a Coal-Based Transport Gasifier,” Fact Sheet NT42391, March 2013, 

http://www.netl.doe.gov/publications/factsheets/project/NT42391.pdf. 

40 Tamar Hallerman, “Miss. Power to Absorb $540M in Cost Increases from Kemper Plant,” GHG Reduction 

Technologies Monitor, April 26, 2013, http://ghgnews.com/index.cfm/miss-power-to-absorb-540m-in-cost-increasesfrom-kemper-plant/. Other reports cite the total costs for the plant. 

41 See Mississippi Power, Kemper IGCC Project, Monthly Status Report Through December 2013, http://www.sec.gov/

Archives/edgar/data/66904/000009212214000002/msmonthlyreport8-kex99x01.htm. 

42 See, for example, Mark Drajem, “Mississippi’s Kemper Coal Plant Overruns Show Risk of EPA Carbon Rule,” 

Bloomberg News, SunHerald.com, September 19, 2013, http://www.sunherald.com/2013/09/19/4964367/kempercounty-coal-plant-overruns.html. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 12 

1). Under the 2010 CCS Roadmap, and with the large infusion of funding from the Recovery Act, 

DOE’s goal is to develop the technologies to allow for commercial-scale demonstration in both 

new and retrofitted power plants and industrial facilities by 2020. The DOE 2011 Strategic Plan

sets a more specific target: to bring at least five commercial-scale CCS demonstration projects 

online by 2016.43

It could be argued that in its allocation of Recovery Act funding, DOE was heeding the 

recommendations of experts44 who identified commercial-scale demonstration projects as the 

most important component, the lynchpin, for future development and deployment of CCS in the 

United States. It could also be argued that much of the future success of CCS is riding on these 

three programs. Accordingly, the following section provides a snapshot of the CCPI, ICCS, and 

FutureGen programs, and a brief discussion of some of their accomplishments and challenges. 

CCS Demonstrations: CCPI, ICCS, and FutureGen 2.0 

Clean Coal Power Initiative 

The Clean Coal Power Initiative was an ongoing program prior to the $800 million funding 

increase from the Recovery Act. This funding now is being used to expand activities in this 

program area for CCPI Round 3 beyond developing technologies to reduce sulfur, nitrogen, and 

mercury pollutants from power plants.45 After enactment of the Recovery Act, DOE did not 

request additional funding for CCPI under its Fossil Energy program in the annual appropriations 

process (Table 1 shows zero dollars for FY2012-FY2014). Rather, in the FY2010 DOE budget 

justification, DOE stated that funding for the these projects in CCPI Round 3 would be supported 

through the Recovery Act, and as a result “DOE will make dramatic progress in demonstrating 

CCS at commercial scale using these funds without the need for additional resources for 

demonstration in 2010.”46 

According to the 2010 DOE CCS Roadmap, Recovery Act funds are being used for these 

demonstration projects to “allow researchers broader CCS commercial-scale experience by 

expanding the range of technologies, applications, fuels, and geologic formations that are being 

tested.”47 DOE selected six projects under CCPI Round 3 through two separate solicitations.48

 

43 U.S. Department of Energy, Strategic Plan, May 2011, p. 18, http://energy.gov/sites/prod/files/

2011_DOE_Strategic_Plan_.pdf. 

44 See, for example, the presentations given by Edward Rubin of Carnegie Mellon University, Howard Herzog of the 

Massachusetts Institute of Technology, and Jeff Phillips of the Electric Power Research Institute, at the CRS seminar 

Capturing Carbon for Climate Control: What’s in the Toolbox and What’s Missing, November 18, 2009. (Presentations 

available from Peter Folger at 7-1517.) Rubin stated that at least 10 full-scale demonstration projects would be needed 

to establish the reliability and true cost of CCS in power plant applications. Herzog also called for at least 10 

demonstration plants worldwide that capture and sequester a million metric tons of CO2 per year. In his presentation, 

Phillips stated that large-scale demonstrations are critical to building confidence among power plant owners. 

45 DOE had solicited and awarded funding for CCPI projects in two previous rounds of funding: CCPI Round 1 and 

Round 2. The Recovery Act funds were to be allocated CCPI Round 3, focusing on projects that utilize CCS 

technology and/or the beneficial reuse of CO2. For more details, see http://www.fossil.energy.gov/programs/

powersystems/cleancoal/. 

46 U.S. Department of Energy, Detailed Budget Justifications FY2010, volume 7, Fossil Energy Research and 

Development, p. 35, http://www.cfo.doe.gov/budget/10budget/Content/Volumes/Volume7.pdf. 

47 DOE 2010 CCS Roadmap, p. 15. 

48 The first solicitation closing date was January 20, 2009; the second solicitation closing date was August 24, 2009. 

Thus the first set of project proposals were submitted prior to enactment of the Recovery Act. See 

(continued...) 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 13 

The total DOE share of funding would have been $1.75 billion for the six projects in five states: 

Alabama, California, North Dakota, Texas, and West Virginia (Table 2). However, the projects in 

Alabama, North Dakota, and West Virginia withdrew from the program, and currently the DOE 

share for the remaining three projects is $1.03 billion (of a total of over $6 billion for total 

expected costs). With the withdrawal of three CCPI Round 3 projects, DOE’s share of the total 

program costs shrank from over 22% to approximately 17%. 

Table 2. DOE CCS Demonstration Round 3 Projects 

Round 3 

Project Location 

DOE Share of 

Funding 

($ millions) 

Total Project 

Cost 

($ millions) 

Percent 

DOE Share 

Metric Tons of 

CO2 Captured 

Annually 

(millions) 

Project 

Status 

Texas Clean 

Energy Project 

Penwell, TX 450 1,727 26% 2.7b Active 

Hydrogen Energy 

California Project 

Kern County, 

CA 

408 4,028 10% 2.6 Active 

NRG Energy 

Project 

Thompsons, 

TX 

167 338 50% 1.4 Active 

AEP Mountaineer 

Project 

New Haven, 

WV 

334 668 50% 1.5 Withdrawn 

Southern 

Company Project 

Mobile, AL 295 665 44% 1 Withdrawn 

Basin Electric 

Power Project 

Beulah, ND 100 387 26% 0.9 Withdrawn 

Total 1,754 7,813 22.4% 10.1 

Total, Active 

Projectsa

 1,025 6,093 16.8% 6.7 

Sources: DOE Fossil Energy Techline; Environment News Service (March 12, 2010), http://www.ensnewswire.com/ens/mar2010/2010-03-12-093.html; NETL CCPI website, http://www.netl.doe.gov/technologies/

coalpower/cctc/ccpi/index.html; NETL Factsheet: Summit Texas Clean Energy, LLC, March 

2012,http://www.netl.doe.gov/publications/factsheets/project/FE0002650.pdf; NETL Factsheet Hydrogen Energy 

California Project, May 2013, http://www.netl.doe.gov/publications/factsheets/project/FE0000663.pdf; NETL 

Factsheet BRG Energy: W.A. Parish Post Combustion CO2 Capture and Sequestration Project, March 2012, 

http://www.netl.doe.gov/publications/factsheets/project/FE0003311.pdf. 

Notes: DOE funding for the NRG Energy Project was initially announced as up to $154 million (see March 9, 

2009, DOE Techline, http://www.fossil.energy.gov/news/techlines/2010/10005-

NRG_Energy_Selected_to_Receive_DOE.html). A May 2010 DOE fact sheet indicates that funding for NRG is 

$167 million (http://www.netl.doe.gov/publications/factsheets/project/FE0003311.pdf). 

a. Total include amounts that were reallocated from withdrawn projects to active projects. 

b. According to NETL, this amount could be up to 3 million metric tons annually. 

 

(...continued) 

http://www.fossil.energy.gov/programs/powersystems/cleancoal/. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 14 

Reasons for Withdrawal from the CCPI Program 

Commercial sector partners identified a number of reasons for withdrawing from the CCPI 

program, including finances, uncertainty regarding future regulations, and uncertainty regarding 

the future national climate policy. 

Southern Company—Plant Barry 160 MW Project: Southern Company withdrew its Alabama 

Plant Barry project from the CCPI program on February 22, 2010, slightly more than two months 

after DOE Secretary Chu announced $295 million in DOE funding for the 11-year, $665 million 

project that would have captured up to 1 million tons of CO2 per year from a 160 MW coal-fired 

generation unit.49 According to some sources, Southern Company’s decision was based on 

concern about the size of the company’s needed commitment (approximately $350 million) to the 

project, and its need for more time to perform due diligence on its financial commitment, among 

other reasons.50 Southern Company continues work on a much smaller CCS project that would 

capture CO2 from a 25 MW unit at Plant Barry. 

Basin Electric Power—Antelope Valley 120 MW Project: On July 1, 2009, Secretary Chu 

announced $100 million in DOE funding for a project that would capture approximately 1 million 

tons of CO2 per year from a 120 MW electric-equivalent gas stream from the Antelope Valley 

power station near Beulah, ND.51 In December 2010, the Basin Electric Power Cooperative 

withdrew its project from the CCPI program, citing regulatory uncertainty with regard to 

capturing CO2, uncertainty about the project’s cost (one source indicates that the company 

estimated $500 million total cost; DOE estimated $387 million—see Table 2),52 uncertainty of 

environmental legislation, and lack of a long-term energy strategy for the country.53 The project 

would have supplied the captured CO2 to an existing pipeline that transports CO2 from the Great 

Plains Synfuels Plant near Beulah for enhanced oil recovery in Canada’s Weyburn field 

approximately 200 miles north in Saskatchewan. 

American Electric Power—Mountaineer 235 MW Project: In July 2011 American Electric 

Power decided to halt its plans to build a carbon capture plant for a 235 MW generation unit at its 

1.3 gigawatt Mountaineer power plant in New Haven, WV. The project represented Phase 2 of an 

ongoing CCPI project. Secretary Chu had earlier announced a $334 million award for the project 

on December 4, 2009.54 According to some sources, AEP dropped the project because the 

company was not certain that state regulators would allow it to recover the additional costs for the 

CCS project through rate increases charged to its customers.55 In addition, company officials cited 

 

49 MIT Carbon Capture & Sequestration Technologies, Plant Barry Fact Sheet: Carbon Dioxide Capture and Storage 

Project, http://sequestration.mit.edu/tools/projects/plant_barry.html. 

50 Ibid. 

51 U.S. DOE, Fossil Energy Techline, Secretary Chu Announces Two New Projects to Reduce Emissions from Coal 

Plants, July 1, 2009, http://www.fossil.energy.gov/news/techlines/2009/09043-DOE_Announces_CCPI_Projects.html. 

52 Lauren Donovan, “Basin Shelves Lignite’s First Carbon Capture Project,” Bismarck Tribune, December 17, 2010, 

http://bismarcktribune.com/news/local/a5fb7ed8-0a1b-11e0-b0ea-001cc4c03286.html. 

53 Daryl Hill and Tracie Bettenhausen, “Fresh Tech, Difficult Decisions: Basin Electric has a History of Trying New 

Technology,” Basin Electric Power Cooperative newsletter, January-February 2011, http://www.basinelectric.com/

Miscellaneous/pdf/FeatureArticles/Fresh_Tech,_difficul.pdf. 

54 U.S. DOE, Fossil Energy Techline, Secretary Chu Announces $3 Billion Investment for Carbon Capture and 

Sequestration, December 4, 2009, http://www.fossil.energy.gov/news/techlines/2009/09081-

Secretary_Chu_Announces_CCS_Invest.html. 

55 Matthew L. Wald and John M. Broder, “Utility Shelves Ambitious Plan to Limit Carbon,” New York Times, July 13, 

(continued...) 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 15 

broader economic and policy conditions as reasons for cancelling the project.56 Some 

commentators suggested that congressional inaction on setting limits on greenhouse gas 

emissions, as well as the weak economy, may have diminished the incentives for a company like 

AEP to invest in CCS.57 One source concluded that “Phase 2 has been cancelled due to unknown 

climate policy.”58

Reshuffling of Funding for CCPI 

According to DOE, $140 million of the $295 million previously allotted to the Southern 

Company Plant Barry project was redistributed to the Texas Clean Energy project and the 

Hydrogen Energy California project. DOE provided additional funding, resulting in each project 

receiving an additional $100 million above its initial awards.59 The remaining funding from the 

canceled Plant Barry project (up to $154 million) was allotted to the NRG Energy project in 

Texas (see Table 2).60 

According to a DOE source, selection of the Basin Electric Power project was announced but a 

cooperative agreement was never awarded by DOE.61 Funds that were to be obligated for the 

Basin project could therefore have been reallocated within the department, but were rescinded by 

Congress in FY2011 appropriations. 

Some of the funding for the AEP Mountaineer project was rescinded by Congress in FY2012 

appropriations legislation (P.L. 112-74). In the report accompanying P.L. 112-74, Congress 

rescinded a total of $187 million of prior-year balances from the Fossil Energy Research and 

Development account.62 The rescission did not apply to amounts previously appropriated under 

P.L. 111-5; however, funding for the AEP Mountaineer project that was provided by the Recovery 

Act and not spent was returned to the Treasury and not made available to the CCPI program.63

 

(...continued) 

2011, http://www.nytimes.com/2011/07/14/business/energy-environment/utility-shelves-plan-to-capture-carbondioxide.html?_r=1. 

56 Michael G. Morris, chairman of AEP, quoted in Matthew L. Wald and John M. Broder, “Utility Shelves Ambitious 

Plan to Limit Carbon,” The New York Times, July 13, 2011. 

57 Wald and Broder, New York Times, July 13, 2011. 

58 MIT Carbon Capture & Sequestration Technologies, AEP Mountaineer Fact Sheet: Carbon Dioxide Capture and 

Storage Project, http://sequestration.mit.edu/tools/projects/aep_alstom_mountaineer.html. 

59 Telephone conversation with Joseph Giove, DOE Office of Fossil Energy, March 19, 2012. 

60 U.S. DOE Fossil Energy Techline, “Secretary Chu Announces Up To $154 Million for NRG Energy’s Carbon 

Capture and Storage Project in Texas,” March 9, 2010, http://www.fossil.energy.gov/news/techlines/2010/10005-

NRG_Energy_Selected_to_Receive_DOE.html. 

61 Telephone conversation with Joseph Giove, DOE Office of Fossil Energy, April 11, 2011. 

62 U.S. Congress, House Committee on Appropriations, Subcommittee on Military Construction, Veterans Affairs, and 

Related Agencies, Military Construction and Veterans Affairs and Related Agencies Appropriations Act, 2012, 

conference report to accompany H.R. 2055, 112th Cong., 1st sess., December 15, 2011, H.Rept. 112-331 (Washington: 

GPO, 2011), p. 851. 

63 Telephone conversation with Joseph Giove, DOE Office of Fossil Energy, March 19, 2012. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 16 

Industrial Carbon Capture and Storage Projects 

The original DOE ICCS program was divided into two main areas: Area 1, consisting of large 

industrial demonstration projects; and Area 2, consisting of projects to test innovative concepts 

for the beneficial reuse of CO2.

64 Under Area 1, the first phase of the program consisted of 12 

projects cost-shared with private industry, intended to increase investment in clean industrial 

technologies and sequestration projects. Phase 1 projects averaged approximately seven months 

in duration. Following Phase 1, DOE selected three projects for Phase 2 for design, construction, 

and operation.65 The three Phase 2 projects are listed as large-scale demonstration projects in 

Table 3. The total share of DOE funding for the three projects, provided by the Recovery Act, is 

$686 million, or approximately 64% of the sum total Area 1 program cost of $1.075 billion. 

Under Area 2, the initial phase consisted of $17.4 million in Recovery Act funding and $7.7 

million in private-sector funding for 12 projects to engage in feasibility studies to examine the 

beneficial reuse of CO2.

66 In July 2010, DOE selected six projects from the original 12 projects 

for a second phase of funding to find ways of converting captured CO2 into useful products such 

as fuel, plastics, cement, and fertilizer. The six projects are listed under “Innovative 

Concepts/Beneficial Use” in Table 3. The total share of DOE funding for the six projects, 

provided by the Recovery Act, is $141.5 million, or approximately 71% of the sum total cost of 

$198.2 million. 

Since its original conception, the DOE ICCS program has expanded with an additional 22 

projects, funded under the Recovery Act, to accelerate promising technologies for CCS.67 In its 

listing of the 22 projects, DOE groups them into four general categories: (1) Large-Scale Testing 

of Advanced Gasification Technologies; (2) Advanced Turbo-Machinery to Lower Emissions 

from Industrial Sources; (3) Post-Combustion CO2 Capture with Increased Efficiencies and 

Decreased Costs; and (4) Geologic Storage Site Characterization.68 The total share of DOE 

funding for the 22 projects, provided by the Recovery Act, is $594.9 million, or approximately 

78% of the sum total cost of $765.2 million. 

Overall, the total share of federal funding for all the ICCS projects combined is $1.422 billion, or 

approximately 70% of the sum total cost of $2.038 billion. 

 

64 Email from Regis K. Conrad, Director, Division of Cross-Cutting Research, DOE, March 20, 2012. 

65 U.S. DOE, National Energy Technology Laboratory, Major Demonstrations, Industrial Capture and Storage (ICCS): 

Area 1, http://www.netl.doe.gov/technologies/coalpower/cctc/iccs1/index.html#. 

66 U.S. DOE, Recovery Act, Innovative Concepts for Beneficial Reuse of Carbon Dioxide, http://fossil.energy.gov/

recovery/projects/beneficial_reuse.html. 

67 Email from Regis K. Conrad, Director, Division of Cross-Cutting Research, DOE, March 20, 2012. 

68 U.S. DOE, Carbon Capture and Storage from Industrial Sources, Industrial Carbon Capture Project Selections, 

http://fossil.energy.gov/recovery/projects/iccs_projects_0907101.pdf. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 17 

Table 3. DOE Industrial Carbon Capture and Storage (ICCS) Projects 

(showing DOE share of funding and total project cost) 

ICCS Project 

Name Location Type of Project 

DOE Share of 

Funding 

($ millions) 

Total Project 

Cost 

($ millions) 

Percent 

DOE 

Share 

Air Products & 

Chemicals, Inc. 

Port Arthur, 

TX 

Large-Scale 

Demonstration 

284 431 66% 

Archer Daniels 

Midland Co. 

Decatur, IL Large-Scale 

Demonstration 

141 208 68% 

Leucadia Energy, 

LLC 

Lake Charles, 

LA 

Large-Scale 

Demonstration 

261 436 60% 

Alcoa, Inc. Alcoa Center, 

PA 

Innovative 

Concepts/Beneficial Use 

13.5 16.9 80% 

Novomer, Inc. Ithaca, NY Innovative 

Concepts/Beneficial Use 

20.5 25.6 80% 

Touchstone 

Research Lab, 

Ltd. 

Triadelphia, PA Innovative 

Concepts/Beneficial Use 

6.7 8.4 80% 

Phycal, LLC Highland 

Heights, OH 

Innovative 

Concepts/Beneficial Use 

51.4 65 80% 

Skyonic Corp. Austin, TX Innovative 

Concepts/Beneficial Use 

28 39.6 70% 

Calera Corp. Los Gatos, CA Innovative 

Concepts/Beneficial Use 

21.4 42.7 50% 

Air Products & 

Chemicals, Inc. 

Allentown, PA Advanced Gasification 

Technologies 

71.7 75 96% 

Eltron Research 

& Development, 

Inc. 

Boulder, CO Advanced Gasification 

Technologies 

71.4 73.7 97% 

Research 

Triangle Institute 

Research 

Triangle Park, 

NC 

Advanced Gasification 

Technologies 

168.8 174 97% 

GE Energy Schenectady, 

NY 

Advanced TurboMachinery 31.3 62.6 50% 

Siemens Energy Orlando, FL Advanced TurboMachinery 32.3 64.7 50% 

Clean Energy 

Systems, Inc. 

Rancho 

Cordova, CA 

Advanced TurboMachinery 30 42.9 70% 

Ramgen Power 

Systems 

Bellevue, WA Advanced TurboMachinery 50 79.7 63% 

ADA-ES, Inc. Littleton, CO Post-Combustion 

Capture 

15 18.8 80% 

Alstom Power Windsor, CT Post-Combustion 

Capture 

10 12.5 80% 

Membrane 

Technology & 

Research, Inc. 

Menlo Park, CA Post-Combustion 

Capture 

15 18.8 80% 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 18 

ICCS Project 

Name Location Type of Project 

DOE Share of 

Funding 

($ millions) 

Total Project 

Cost 

($ millions) 

Percent 

DOE 

Share 

Praxair Tonawanda, 

NY 

Post-Combustion 

Capture 

35 55.6 63% 

Siemens Energy, 

Inc. 

Pittsburgh, PA Post-Combustion 

Capture 

15 18.8 80% 

Board of 

Trustees U. of IL 

Champaign, IL Geologic Site 

Characterization 

5 6.5 77% 

N. American 

Power Group, 

Ltd. 

Greenwood 

Village, CO 

Geologic Site 

Characterization 

5 7.85 64% 

Sandia 

Technologies, 

LLC 

Houston, TX Geologic Site 

Characterization 

4.38 5.63 78% 

S. Carolina 

Research 

Foundation 

Columbia, SC Geologic Site 

Characterization 

5 6.25 80% 

Terralog 

Technologies 

USA, Inc. 

Arcadia, CA Geologic Site 

Characterization 

5 6.25 80% 

U. of Alabama Tuscaloosa, AL Geologic Site 

Characterization 

5 10.8 46% 

U. of Kansas 

Center for 

Research, Inc. 

Lawrence, KS Geologic Site 

Characterization 

5 6.29 80% 

U. of Texas at 

Austin 

Austin, TX Geologic Site 

Characterization 

5 6.25 80% 

U. of Utah Salt Lake City, 

UT 

Geologic Site 

Characterization 

5 7.23 69% 

U. of Wyoming Laramie, WY Geologic Site 

Characterization 

5 5 100% 

Totals 1,422.4 2,038.4 70% 

Source: Emails from Regis K. Conrad, Director, Division of Cross-Cutting Research, DOE, March 20 and March 

27, 2012; U.S. DOE, National Energy Technology Laboratory, Major Demonstrations, Industrial Capture and Storage 

(ICCS): Area 1, http://www.netl.doe.gov/technologies/coalpower/cctc/iccs1/index.html#; U.S. DOE, Carbon Capture 

and Storage from Industrial Sources, Industrial Carbon Capture Project Selections, http://fossil.energy.gov/recovery/

projects/iccs_projects_0907101.pdf. 

Notes: Table is ordered from top to bottom by type of project: Large-Scale Demonstration; Innovative 

Concepts/Beneficial Use; Advanced Gasification Technologies; Advanced Turbo-Machinery; Post-Combustion 

Capture; and Geologic Site Characterization. Totals may not add due to rounding. 

FutureGen—A Special Case? 

On February 27, 2003, President George W. Bush proposed a 10-year, $1 billion project to build a 

coal-fired power plant that would integrate carbon sequestration and hydrogen production at a 

275 megawatt-capacity plant, enough to power about 150,000 average U.S. homes. As originally 

conceived, the plant would have been a coal-gasification facility and would have produced and 

sequestered between 1 million and 2 million tons of CO2 annually. On January 30, 2008, DOE 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 19 

announced that it was “restructuring” the FutureGen program away from a single, state-of-the-art 

“living laboratory” of integrated R&D technologies—a single plant—to instead pursue a new 

strategy of multiple commercial demonstration projects.69 In the restructured program, DOE 

would support up to two or three demonstration projects of at least 300 megawatts that would 

sequester at least 1 million tons of CO2 per year. 

In the Bush Administration’s FY2009 budget, DOE requested $156 million for the restructured 

FutureGen program, and specified that the federal cost-share would only cover the CCS portions 

of the demonstration projects, not the entire power system. However, after the Recovery Act was 

enacted on February 17, 2009, Secretary Chu announced an agreement with the FutureGen 

Alliance—an industry consortium—to advance construction of the FutureGen plant built in 

Mattoon, IL, the site selected by the FutureGen Alliance in 2007.70 Further, DOE anticipated that 

$1 billion of funding from the Recovery Act would be used to support the project.71 

On August 5, 2010, then-Secretary of Energy Chu announced the $1 billion award, from 

Recovery Act funds, to the FutureGen Alliance, Ameren Energy Resources, Babcock & Wilcox, 

and Air Liquide Process & Construction, Inc., to build FutureGen 2.0.72 FutureGen 2.0 differs 

from the original concept for the plant, because it would retrofit Ameren’s existing power plant in 

Meridosia, IL, with oxy-combustion technology at a 202 MW oil-fired unit,73 rather than build a 

new state-of-the-art plant in Mattoon.74 

Challenges to FutureGen—A Similar Path for Other Demonstration Projects? 

More than a decade after the George W. Bush Administration announced FutureGen—its 

signature clean coal power initiative—the program is still in early development. Among the 

challenges to the development of FutureGen 2.0 are rising costs of production, ongoing issues 

with project development, lack of incentives for investment from the private sector, time 

constraints, and competition with foreign nations. Remaining challenges to FutureGen’s 

development include securing private sector funding to meet increasing costs, purchasing the 

power plant for the project, obtaining permission from DOE to retrofit the plant, performing the 

retrofit, and then meeting the goal of 90% capture of CO2.

75

A question for Congress is whether FutureGen represents a unique case of a first mover in a 

complex, expensive, and technically challenging endeavor, or whether it represents all large CCS 

 

69 See http://www.fossil.energy.gov/news/techlines/2008/08003-DOE_Announces_Restructured_FutureG.html. 

70 Prior to when DOE first announced it would restructure the program in 2008, the FutureGen Alliance announced on 

December 18, 2007, that it had selected Mattoon, IL, as the host site from a set of four finalists. The four were Mattoon, 

IL; Tuscola, IL; Heart of Brazos (near Jewett, TX); and Odessa, TX. 

71 See DOE announcement on June 12, 2009, http://www.fossil.energy.gov/news/techlines/2009/09037-

DOE_Announces_FutureGen_Agreement.html. 

72 See DOE Techline, http://www.netl.doe.gov/publications/press/2010/10033-

Secretary_Chu_Announces_FutureGen_.html. 

73 Ameren had planned to replace the oil-fired boiler with a coal-fired boiler using oxy-combustion technology to allow 

carbon capture. See http://www.futuregenalliance.org/pdf/FutureGen%20FAQ-General%20042711.pdf. 

74 For more information about the history of FutureGen, and issues for Congress, see CRS Report R43028, The 

FutureGen Carbon Capture and Sequestration Project: A Brief History and Issues for Congress, by Peter Folger 

75 For more information on FutureGen, see CRS Report R43028, The FutureGen Carbon Capture and Sequestration 

Project: A Brief History and Issues for Congress, by Peter Folger 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 20 

demonstration projects once they move past the planning stage. As discussed above, 

approximately $3.3 billion of Recovery Act funding is committed to large demonstration projects, 

including FutureGen. A rationale for committing such a substantial level of funding to 

demonstration projects was to scale up CCS RD&D more quickly than had been the pace of 

technology development prior to enactment of the Recovery Act. However, if all the CCS 

demonstration projects encounter similar changes in scope, design, location, and cost as 

FutureGen, the goals laid out in the DOE 2011 Strategic Plan—namely, to bring at least five 

commercial-scale CCS demonstration projects online by 2016—may be in jeopardy. 

Alternatively, one could argue that FutureGen from its original conception was unique. None of 

the other large-scale demonstration projects share the same original ambitious vision: to create a 

new, one-of-a-kind, near-zero emission CCS plant from the ground up. Even though the 

individual components of FutureGen—as originally conceived—were not themselves new 

innovations, combining the capture, transportation, and storage components together into a 250-

megawatt functioning power plant could be considered unprecedented and therefore most likely 

to experience delays at each step in development. 

Scholars have described the stages of technological change in different schemes, such as 

• invention, innovation, adoption, diffusion;76 or 

• technology readiness levels (TRLs) ranging from TRL 1 (basic technology 

research) to TRL 9 (system test, launch, and operations);77 or 

• conceptual design, laboratory/bench scale, pilot plant scale, full-scale 

demonstration plant, and commercial process.78

FutureGen is difficult to categorize within these schemes, in part because the project spanned a 

range of technology development levels irrespective of the particular scheme. The original 

conception of the FutureGen project arguably had aspects of conceptual design through 

commercial processes—all five components of the scheme listed as the third bullet above—which 

meant that the project was intended to march through all stages in a linear fashion. As some 

scholars have noted, however, the stages of technological change are highly interactive, requiring 

learning by doing and learning by using, once the project progresses past its innovative stage into 

larger-scale demonstration and deployment.79 The task of tackling all the stages of technology 

development in one project—the original FutureGen—might have been too daunting and, in 

addition to other factors, contributed to the project’s erratic progress since 2003. It remains to be 

seen whether the current large-scale demonstration projects funded by DOE under CCPI Round 3 

follow the path of FutureGen or instead achieve their technological development goals on time 

and within their current budgets. Presumably, lessons learned during the planning, construction, 

 

76 E. S. Rubin, “The Government Role in Technology Innovation: Lessons for the Climate Change Policy Agenda,” 

Institute of Transportation Studies, 10th Biennial Conference on Transportation Energy and Environmental Policy, 

University of California, Davis, CA (August 2005). 

77 National Aeronautics and Space Administration, “Definition of Technology Readiness Levels,” at 

http://esto.nasa.gov/files/TRL_definitions.pdf. 

78 For a more thorough discussion of different schemes describing stages of technology development, see chapter 4 of 

CRS Report R41325, Carbon Capture: A Technology Assessment, by Peter Folger. 

79 E. S. Rubin, “The Government Role in Technology Innovation: Lessons for the Climate Change Policy Agenda,” 

Institute of Transportation Studies, 10th Biennial Conference on Transportation Energy and Environmental Policy, 

University of California, Davis, CA (August 2005). 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 21 

and operation of these demonstration projects will be shared with the broader electric power 

industry.80

Geologic Sequestration/Storage: DOE RD&D for the 

Last Step in CCS 

DOE has allocated $112 million in FY2012, $110 million in FY2013, and $109 million in 

FY2014 for its carbon sequestration/storage activities. (See Table 1.) In contrast with the carbon 

capture technology RD&D, which received nearly all of the $3.4 billion from Recovery Act 

funding, carbon sequestration/carbon storage activities received approximately $50 million in 

Recovery Act funds. Recovery Act funds were awarded for 10 projects to conduct site 

characterization of promising geologic formations for CO2 storage.81 

Brief History of DOE Geological Sequestration/Storage Activities 

DOE has devoted the bulk of its funding for geological sequestration/storage activities to RD&D 

efforts for injecting CO2 into subsurface geological reservoirs. Injection and storage is the third 

step in the CCS process following the CO2 capture step and CO2 transport step. One part of the 

RD&D effort is characterizing geologic reservoirs (which received a $50 million boost from 

Recovery Act funds, as noted above); however, the overall program is much broader than just 

characterization, and has now reached the beginning of the phase of large-volume CO2 injection 

demonstration projects across the country. According to DOE, these large-volume tests are 

needed to validate long-term storage in a variety of different storage formations of different 

depositional environments, including deep saline reservoirs, depleted oil and gas reservoirs, low 

permeability reservoirs, coal seams, shale, and basalt.82 The large-volume tests can be considered 

injection experiments conducted at a commercial scale (i.e., approximately 1 million tons of CO2

injected per year) that should provide crucial information on the suitability of different geologic 

reservoirs; monitoring, verification, and accounting of injected CO2; risk assessment protocols for 

long-term injection and storage; and other critical challenges. 

In 2003 DOE created seven regional carbon sequestration partnerships (RCSPs), essentially 

consortia of public and private sector organizations grouped by geographic region across the 

United States and parts of Canada.83 The geographic representation was intended to match 

regional differences in fossil fuel use and geologic reservoir potential for CO2 storage.84 The 

 

80 Another possible source of uncertainty for FutureGen, and other large industrial CCS projects, is cost recovery 

during the operating phase of the plant after the construction phase and initial capital investments are made. “Learning 

by doing” should increase operating efficiency, but it is unclear by how much and over what time span. For more 

discussion on cost trajectories and expected efficiency gains, see CRS Report R41325, Carbon Capture: A Technology 

Assessment, by Peter Folger. 

81 The total DOE share for the 10 projects is $46.6 million. See DOE, Recovery Act, http://fossil.energy.gov/recovery/

projects/site_characterization.html. 

82 DOE 2010 CCS Roadmap, p. 55. 

83 Four Canadian provinces are partners with DOE in two of the regional partnerships, and are members with other 

participating organizations that are contributing funding and other support to the partnerships. 

84 DOE National Energy Technology Laboratory, Carbon Sequestration Regional Carbon Sequestration Partnerships, 

http://www.netl.doe.gov/technologies/carbon_seq/infrastructure/rcsp.html. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 22 

RCSPs cover 43 states and 4 Canadian provinces and include over 400 organizations, according 

to the DOE 2011 Strategic Plan. Table 4 shows the seven partnerships, the lead organization for 

each, and the states and provinces included. Several states belong to more than one RCSP. 

Table 4. Regional Carbon Sequestration Partnerships 

Regional Carbon 

Sequestration Partnership 

(RCSP) Lead Organization 

States and Provinces in the 

Partnership 

Big Sky Carbon Sequestration 

Partnership (BSCSP) 

Montana State University-Bozeman MT, WY, ID, SD, eastern WA, 

eastern OR 

Midwest Geological Sequestration 

Consortium (MGSC) 

Illinois State Geological Survey IL, IN, KY 

Midwest Regional Carbon 

Sequestration Partnership 

(MRCSP) 

Battelle Memorial Institute IN, KY, MD, MI, NJ, NY, OH, PA, 

WV, 

Plains CO2 Reduction Partnership 

(PCOR) 

University of North Dakota Energy 

and Environmental Research Center 

MT, northeast WY, ND, SD, NE, MN, 

IA, MO, WI, Manitoba, Alberta, 

Saskatchewan, British Columbia 

(Canada) 

Southeast Regional Carbon 

Sequestration Partnership 

(SECARB) 

Southern States Energy Board AL, AS, FL, GA, LA, MS, NC, SC, TN, 

TX, VA, portions of KY and WV 

Southwest Regional Partnership 

on Carbon Sequestration (SWP) 

New Mexico Institute of Mining and 

Technology 

AZ, CO, OK, NM, UT, KS, NV, TX, 

WY 

West Coast Regional Carbon 

Sequestration Partnership 

(WESTCARB) 

California Energy Commission AK, AZ, CA, HI, OR, NV, WA, British 

Columbia (Canada) 

 

Source: DOE National Energy Technology Laboratory, Carbon Sequestration Regional Carbon Sequestration 

Partnerships, http://www.netl.doe.gov/technologies/carbon_seq/infrastructure/rcsp.html. 

The RCSPs have pursued their objectives through three phases beginning in 2003: 

(1) Characterization Phase (2003 to 2005), an initial examination of the region’s potential for 

geological sequestration of CO2; (2) Validation Phase (2005 to 2011), small-scale injection field 

tests (less than 500,000 tons of CO2) to develop a better understanding of how different geologic 

formations would handle large amounts of injected CO2; and (3) Development Phase (2008 to 

2018 and beyond), injection tests of at least 1 million tons of CO2 to simulate commercial-scale 

quantities of injected CO2.

85 The last phase is intended also to collect enough information to help 

understand the regulatory, economic, liability, ownership, and public outreach requirements for 

commercial deployment of CCS. 

There are RD&D activities funded by DOE under its carbon sequestration/carbon storage 

program activities other than the RCSPs, such as geological storage technologies; monitoring, 

verification, and assessment; carbon use and reuse; and others. However, the RCSPs were 

allocated approximately 70% of annual spending on carbon sequestration/carbon storage in 

FY2012, and comprised 66% of that account in the FY2014 budget request. The RCSPs provide 

 

85 Ibid. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 23 

the framework and infrastructure for a wide variety of DOE geologic sequestration/storage 

activities. 

Current Status and Challenges to Carbon Sequestration/Storage 

The third phase—Development—is currently underway for all the RCSPs, and large-scale CO2

injection has begun for the SECARB and MGSC projects.86 The Development Phase large-scale 

injection projects are arguably akin to the large-scale carbon capture demonstration projects 

discussed above (See Table 2). They are needed to understand what actually happens to CO2

underground when commercial-scale volumes are injected in the same or similar geologic 

reservoirs as would be used if CCS were deployed nationally. 

In addition to understanding the technical challenges to storing CO2 underground without leakage 

over hundreds of years, DOE also expects that the Development Phase projects will provide a 

better understanding of regulatory, liability, and ownership issues associated with commercialscale CCS.87 These nontechnical issues are not trivial, and could pose serious challenges to 

widespread deployment of CCS even if the technical challenges of injecting CO2 safely and in 

perpetuity are resolved. For example, a complete regulatory framework for managing the 

underground injection of CO2 has not been developed in the United States. However, EPA 

promulgated a rule under the authority of the Safe Drinking Water Act (SDWA) that creates a new 

class of injection wells under the existing Underground Injection Control Program. The new class 

of wells (Class VI) establishes national requirements specifically for injecting CO2 and protecting 

underground sources of drinking water. EPA’s stated purpose in proposing the rule was to ensure 

that CCS can occur in a safe and effective manner in order to enable commercial-scale CCS to 

move forward.88

The development of the regulation for Class VI wells highlighted that EPA’s authority under the 

SDWA is limited to protecting underground sources of drinking water but does not address other 

major issues. Some of these include the long-term liability for injected CO2, regulation of 

potential emissions to the atmosphere, legal issues if the CO2 plume migrates underground across 

state boundaries, private property rights of owners of the surface lands above the injected CO2

plume, and ownership of the subsurface reservoirs (also referred to as pore space).89 Because of 

these issues and others, there are some indications that broad community acceptance of CCS may 

be a challenge. The large-scale injection tests may help identify the key factors that lead to 

community concerns over CCS, and help guide DOE, EPA, other agencies, and the private sector 

towards strategies leading to the widespread deployment of CCS. Currently, however, the general 

public is largely unfamiliar with the details of CCS and these challenges have yet to be resolved.90

 

86 For details on the two large-scale injection experiments by SECARB, see http://www.secarbon.org/; for details on 

the large-scale injection experiment by MGSC, see http://sequestration.org/. 

87 DOE National Energy Technology Laboratory, Carbon Sequestration Regional Partnership Development Phase 

(Phase III) Projects, http://www.netl.doe.gov/technologies/carbon_seq/infrastructure/rcspiii.html. 

88 For more information on the EPA Class VI wells in particular, and the Safe Drinking Water Act generally, see CRS 

Report RL34201, Safe Drinking Water Act (SDWA): Selected Regulatory and Legislative Issues, by Mary Tiemann. 

89 For a discussion of several of these legal issues, see CRS Report RL34307, Legal Issues Associated with the 

Development of Carbon Dioxide Sequestration Technology, by Adam Vann and Paul W. Parfomak. 

90 For more information on the different issues regarding community acceptance of CCS, see CRS Report RL34601, 

Community Acceptance of Carbon Capture and Sequestration Infrastructure: Siting Challenges, by Paul W. Parfomak. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 24 

Outlook 

Testimony from Scott Klara of the National Energy Technology Laboratory sums up a crucial 

metric for the success of the federal CCS RD&D program, namely, whether CCS technologies are 

deployed in the commercial marketplace: 

The success of the Clean Coal Program will ultimately be judged by the extent to which emerging 

technologies get deployed in domestic and international marketplaces. Both technical and 

financial challenges associated with the deployment of new “high risk” coal technologies must be 

overcome in order to be capable of achieving success in the marketplace. Commercial scale 

demonstrations help the industry understand and overcome startup issues, address component 

integration issues, and gain the early learning commercial experience necessary to reduce risk and 

secure private financing and investment for future plants.91

To date, there are no commercial ventures in the United States that capture, transport, and inject 

large quantities of CO2 (e.g., 1 million tons per year or more) solely for the purposes of carbon 

sequestration. 

However, the CCS RD&D program has embarked on commercial-scale demonstration projects 

for CO2 capture, injection, and storage. The success of these demonstration projects will likely 

bear heavily on the future outlook for widespread deployment of CCS technologies as a strategy 

for preventing large quantities of CO2 from reaching the atmosphere while plants continue to burn 

fossil fuels, mainly coal. The September 20, 2013, re-proposal of an EPA standard to limit CO2

emissions from coal-fired power plants has invited renewed scrutiny of CCS technology and its 

prospects for commercial deployment. Congress may wish to carefully review the results from 

these demonstration projects as they progress in order to gauge whether DOE is on track to meet 

its goal of allowing for an advanced CCS technology portfolio to be ready by 2020 for large-scale 

demonstration and deployment in the United States. 

In addition to the issues and programs discussed above, other factors might affect the 

demonstration and deployment of CCS in the United States. The use of hydraulic fracturing 

techniques to extract unconventional natural gas deposits recently has drawn national attention to 

the possible negative consequences of deep well injection of large volumes of fluids. Hydraulic 

fracturing involves the high-pressure injection of fluids into the target formation to fracture the 

rock and release natural gas or oil. The injected fluids, together with naturally occurring fluids in 

the shale, are referred to as produced water. Produced waters are pumped out of the well and 

disposed of. Often the produced waters are disposed of by re-injecting them at a different site in a 

different well. These practices have raised concerns about possible leakage as fluids are pumped 

into and out of the ground, and about deep-well injection causing earthquakes. Public concerns 

over hydraulic fracturing and deep-well injection of produced waters may spill over into concerns 

about deep-well injection of CO2. How successfully DOE is able to address these types of 

concerns as the large-scale demonstration projects move forward into their injection phases could 

affect the future of CCS deployment. 

 

91 Testimony of Scott Klara, Deputy Laboratory Director, National Energy Technology Laboratory, U.S. Department of 

Energy, in U.S. Congress, Senate Energy and Natural Resources Committee, Carbon Capture and Sequestration 

Legislation, hearing to receive testimony on carbon capture and sequestration legislation, including S. 699 and S. 757, 

112th Cong., 1st sess., May 12, 2011, S.Hrg. 112-22. 
Carbon Capture and Sequestration: Research, Development, and Demonstration at DOE 

Congressional Research Service 25 

Author Contact Information 

Peter Folger 

Specialist in Energy and Natural Resources Policy 

pfolger@crs.loc.gov, 7-1517