Carbon Capture and Sequestration: Research, Development, and Demonstration at the U.S. Department of Energy
Released: 2015-04-24T00:00:00

Introduction

Carbon capture and sequestration (or storage)—known as CCS—is a physical process that involves capturing manmade carbon dioxide (CO 2 ) at its source and storing it before its release to the atmosphere. CCS could reduce the amount of CO 2 emitted to the atmosphere from 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 CO 2 at its source and separating it from other gases; (2) purifying, compressing, and transporting the captured CO 2 to the sequestration site; and (3) injecting the CO 2 into subsurface geological reservoirs. Following its injection into a subsurface reservoir, the CO 2 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 CO 2 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. Congress has appropriated nearly $7 billion in total since FY2008 for CCS research, development, and demonstration (RD&D) at DOE's Office of Fossil Energy: nearly $3.5 billion in total annual appropriations (including FY2015) 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 . (In part, the roadmap was intended to lay out a path for rapid technological development of CCS so that the United States could continue to use fossil fuels despite potential carbon restrictions.) 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. FutureGen had experienced delays and multiple changes of scope and design since its inception in 2003, and on February 3, 2015, DOE announced that it was suspending the project. (For more details, see sections below on " FutureGen—A Special Case? " and " Lessons from FutureGen: A Similar Path for Other Demonstration Projects? ")

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.

Issues for Congress

U.S. Environmental Protection Agency (EPA) proposed rules and guidelines for reducing greenhouse gas (GHG) emissions from new and existing coal-fired power plants have been a focal point of discussion in Congress about CCS. How the demise of FutureGen will affect that debate is yet to be seen. Legislation regarding CCS in the last Congress mainly focused on two issues: stopping or slowing implementation of the EPA GHG rules and guidelines and providing federal incentives to accelerate the demonstration and development of CCS at commercial scales.

EPA Proposed Rule: Limiting CO2 Emissions from Power Plants5

In 2014, EPA proposed emission standards for new and existing fossil-fueled electric generating units under Section 111 of the Clean Air Act. EPA's regulatory proposal stems from the Obama Administration's stated goal to take action on climate change in the absence of congressional action to reduce GHG emissions through legislation. In June 2013, President Obama directed EPA to propose standards for GHG emissions from new fossil-fueled power plants by September 20, 2013, and to propose guidelines for existing power plants by June 1, 2014. EPA met both deadlines and may finalize the power plant rules by mid-summer 2015.

New Power Plants

According to EPA, new natural gas-fired stationary power plants should be able to meet the proposed standard without additional cost and without the need for add-on control technology. However, the only apparent technical way for new coal-fired plants to meet the standard would be to install CCS technology to capture about 40% of the CO 2 they typically produce. The proposed standard allows for a seven-year compliance period for coal-fired plants but would demand a more stringent standard for those plants that comply over seven years; CO 2 emissions for these plants would be limited to an average of 1,000-1,050 pounds per megawatt-hour.

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. 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. 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, cost-effective carbon management that will meet our Nation's goals for reducing [greenhouse gas] emissions."

Existing Power Plants

One analysis concluded that the debate over EPA's proposed rule for new power plants is largely symbolic and that its real significance is that without the promulgation of a rule for new sources, EPA could not proceed to regulate existing power plants under the Clean Air Act. The proposed guidelines for existing plants would establish different goals for each state based on four factors: improved efficiency at coal-fired plants; substitution of natural gas combined cycle generation for coal-fired power; zero-emission generation from renewables and nuclear power; and demand-side efficiency. Although CCS was not specifically included as a factor, or as part of the four factors listed above, the rule would not preclude CSS as an option for reducing emissions to help states meet their emissions target.

Implications for CCS Research, Development, and Deployment

Given the pending EPA rule, congressional interest in the future of coal as a domestic energy source also appears to be linked to the future of CCS. The debate has been mixed as to whether the proposed rule for new plants 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 will take place and what role EPA regulations will play in causing them are matters of dispute.

Part of the argument over the proposed rule for new plants has focused on whether CCS is the best system of emissions reduction (BSER) for coal plants and whether it has been "adequately demonstrated" 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.) 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. The shift appears to be largely due to the cheaper and increasingly abundant fuel—natural gas—compared to coal for electricity production. The EPA re-proposed rule 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 generation 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 CO 2 emissions may lead electric power producers to invest in natural gas-fired plants, which emit approximately half the amount of CO 2 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 (e.g., see " Lessons from FutureGen: A Similar Path for Other Demonstration Projects? ").

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 for new power plants, EPA cited technology as one of four factors that it considers in making a BSER determination. 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 asserted 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.

FutureGen—A Special Case?

On February 27, 2003, President George W. Bush proposed a 10-year, $1 billion project known as FutureGen 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 CO 2 annually. On January 30, 2008, DOE 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 pursue instead a new strategy of multiple commercial demonstration projects. In the restructured program, DOE announced that it would support up to two or three demonstration projects of at least 300 megawatts that would sequester at least 1 million tons of CO 2 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 cover only the CCS portions of the demonstration projects, not the entire power system. However, after the Recovery Act was enacted on February 17, 2009, Secretary of Energy Chu announced an agreement with the FutureGen Alliance—an industry consortium—to advance construction of the FutureGen plant built in Mattoon, Illinois, the site selected by the FutureGen Alliance in 2007. Further, DOE anticipated that $1 billion of funding from the Recovery Act would be used to support the project.

On August 5, 2010, Secretary 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. FutureGen 2.0 differed from the original concept for the plant because it aimed to retrofit Ameren's existing power plant in Meridosia, Illinois, with oxy-combustion technology at a 202 megawatt oil-fired unit, rather than build a new, state-of-the-art plant in Mattoon.

On February 3, 2015, DOE announced it was canceling funding for the FutureGen project. The most pressing reason for the program's suspension is the September 30, 2015, deadline for spending the Recovery Act funding and the likelihood that the FutureGen Alliance would not be able to commit the funds by that date, which, in turn, led to uncertainty about the alliance's ability to secure private-sector funding to make up the rest of the project costs after Recovery Act funding was exhausted. The FutureGen Alliance had spent approximately $200 million of the nearly $1 billion in Recovery Act funding appropriated and allocated to FutureGen. Other factors also may have played a role in DOE's decision.

Lessons from FutureGen: A Similar Path for Other Demonstration Projects?

Following the announcement that DOE was suspending the FutureGen project, one question for Congress is whether FutureGen represented a unique case of a first mover in a complex, expensive, and technically challenging endeavor. Another is whether some of the challenges that ultimately stopped FutureGen also apply to other large DOE-funded CCS demonstration projects once they move past the planning stage. DOE committed approximately $3.3 billion of Recovery Act funding to large demonstration projects (approximately $800 million less now, with the demise of FutureGen). One rationale for committing such a substantial level of funding was to scale up and quicken the pace of CCS RD&D.

Some argue that FutureGen was unique from its original conception. None of the other large-scale demonstration projects in the United States 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 it was originally conceived were not themselves new innovations, combining the capture, transportation, and storage components into a 250-megawatt functioning power plant could be considered unprecedented and therefore 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; or technology readiness levels (TRLs) ranging from TRL 1 (basic technology research) to TRL 9 (system test, launch, and operations); or conceptual design, laboratory/bench scale, pilot plant scale, full-scale demonstration plant, and commercial process.

FutureGen was 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 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. 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 remaining large-scale demonstration projects funded by DOE under the Clean Coal Power Initiative (CCPI) Round 3 follow the path of FutureGen or achieve their technological development goals on time and within their current budgets. Presumably, lessons learned during the planning, construction, and operation of these demonstration projects will be shared with the broader electric power industry.

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. 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. (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 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.

114th Congress

On February 26, 2015, Senators Heitkamp and Kaine introduced S. 601 , the Advanced Clean Technology Investment in Our Nation Act of 2015, which would promote CCS for coal-fired utilities by a combination of loan guarantees, tax credits, and support for the DOE R&D effort in its coal program, among other things. The bill closely resembles legislation introduced by Senator Heitkamp in the 113 th Congress, S. 2152 (discussed below).

113th Congress

More than a dozen bills introduced in the 113 th Congress would have addressed the proposed EPA rules and guidelines for reducing GHG emissions from new and existing coal-fired power plants. H.R. 3826 , the Electricity Security and Affordability Act, would have set requirements EPA must meet before the agency could issue GHG emission regulations under Section 111 of the Clean Air Act. The bill would have, in part, prohibited EPA from promulgating or implementing GHG emissions standards for fossil-fueled power plants until at least six power plants representative of the operating characteristics of electric generation units at different locations across the United States had demonstrated compliance with proposed emission limits for a continuous period of 12 months on a commercial basis. Companion legislation, S. 1905 , was referred to the Senate Committee on Environment and Public Works.

Several bills introduced in the 113 th Congress would have provided federal incentives for accelerating the RD&D of CCS. For example, S. 2152 would have increased DOE CCS research and development, allowed for loan guarantees to qualified CCS projects, provided an investment tax credit for certain CCS facilities, and created a clean energy coal bond, among other things. Two related bills would have dealt with tax credits and loan guarantees. S. 2287 would have revised part of the tax code that allows a tax credit for CCS and would have amended EPAct to broaden the loan guarantee program for CCS, among other things. S. 2288 would have amended the tax code to expand the tax credits for CCS. S. 2776 would have established a fund for DOE to administer in establishing at least 10 commercial-scale CCS projects over 10 years. Several other bills introduced in the 113 th Congress would have touched on CCS-related issues.

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." 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. The Coal Program represented between 68% and 70% of total Fossil Energy Research and Development appropriations from FY2012 to FY2015, 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 CO 2 , and that CCS is a promising option for addressing this challenge." The FY2016 President's budget request, however, would reduce the total funding for the Coal Program compared with the previous two fiscal years. In the FY2016 request, the coal program would represent 66% of the total Fossil Energy R&D appropriation.

DOE acknowledges that the cost of deploying currently available CCS technologies is very high and that to be effective as a technology for mitigating GHG 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%. The challenge of reducing the costs of CCS technology is difficult to quantify. The Boundary Dam Plant in Canada is the only commercial-scale coal-fired power plant equipped with CCS, and it has been operating for less than one year.

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." Thus the coal RD&D program is 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. In addition, one remaining active project in the CCPI program that received funding in Round 2, prior to enactment of the Recovery Act—the Kemper County Energy Facility—also is discussed. Lastly, the Boundary Dam Project is described briefly, although it is a Canadian venture, because of its unique status as the only currently operating commercial-scale coal-fired power plant with CCS in the world.

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) CCPI; (9) FutureGen; and (10) Industrial Carbon Capture and Storage Projects (ICCS).

Coal Program Areas

DOE changed the program structure for coal after FY2010, renaming and consolidating program areas. The program areas are divided into two main categories: (1) CCS Demonstration Programs and (2) CSS and Power Systems. Table 1 shows the current program structure and indicates which programs received Recovery Act funding. In its FY2016 budget justification, DOE states that the CCS and Power Systems R&D program

supports secure, affordable, and environmentally acceptable near-zero emissions fossil energy technologies through research, development, and demonstration (RD&D) to improve the performance of advanced CCS technologies.

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 post-combustion, 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 CO 2 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.

Within the CCS Demonstrations 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 GHG emissions by boosting plant efficiencies and capturing CO 2 . In contrast, the ICCS program area demonstrates carbon capture technology for the non-power plant industrial sector. 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, industrial-scale carbon capture demonstration projects. Primarily, the call for large-scale CCS demonstration projects that capture 1 million metric tons or more of CO 2 per year reflects the need to reduce the additional costs to the power plant or industrial facility associated with capturing the CO 2 before it is emitted to the atmosphere. The capture component of CCS is the costliest component, according to most experts. The higher estimated costs to build and operate power plants with CCS compared with 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. Some cost data are emerging, however, now that the Kemper County Energy Facility is close to completion and the Canadian Boundary Dam project is operating (both discussed below).

Other Fossil Research and Development

The Administration requests approximately $191 million for FY2016 for other programs pursuing fossil energy R&D and support activities. The largest activity is program direction ($114 million requested), which provides for DOE headquarters support and for federal field and contractor support of the overall fossil energy R&D programs. These activities would support CCS-related activities directly and indirectly. The second-largest activity is natural gas technologies ($44 million), which supports collaborative research to foster safe and prudent development of shale gas resources, the reduction of methane emissions from natural gas infrastructure, and research on gas hydrates. The other activities listed in Table 1 , plant and capital, environmental restoration, and supercomputer, total approximately $33 million in the FY2016 request.

Evolution of Costs

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 (SO 2 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.

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 SO 2 and NOx scrubbers, efforts typically took two decades or more to bring new concepts (such as combined SO 2 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 CO 2 capture costs if the technologies become widely deployed.

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

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 (TRIG TM ).

The Kemper County Project is an integrated gasification combined-cycle (IGCC) power plant that will be owned and operated by Mississippi Power Company, a subsidiary of Southern Company, and which will use lignite as a fuel source. The plant is expected to have an estimated peak net output capability of 582 megawatts, and is designed to capture 65% of the total CO 2 emissions released from the plant. According to DOE, this would make the CO 2 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 megawatt-hour limit as required by the new EPA proposed rule. The estimated 3 million tons of CO 2 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 has been delayed several times since construction began in 2010. According to a Mississippi Power timeline for the project, commercial operation will begin sometime in 2016. The project also has cost far more than the original estimate. The $270 million award under Round 2 of the CCPI program represented approximately 10% of what DOE had reported as the overall cost to build the plant, approximately $2.67 billion. 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. In early April 2014, 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, CO 2 pipeline, land purchase, and all the other components of the full project, had risen to approximately $5.2 billion. In late April 2014, Mississippi Power again modified its cost and schedule estimates, adjusting costs upward by $61 million related to construction issues and $135 million related to the extension of the start-up date into 2015. According to some reports, the overall cost of the plant may now exceed $6 billion when complete and ready for commercial operation, and the schedule for start-up of commercial operations has been pushed to 2016.

It is likely that the plant will attract increased scrutiny in the wake of the EPA proposed rule on CO 2 emissions, and its cost and schedule overruns evaluated against the promised environmental benefits due to CCS technology. As Figure 1 shows, 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.

Canada's Boundary Dam Project: The World's First Commercial-Scale CCS Project

The Boundary Dam Project, operated by SaskPower, is a Canadian venture, and it is the only commercial-scale power plant with CCS operating in the world. Some of its published cost and schedule data may be helpful to those trying to understand the financing and time requirements for other commercial-scale CCS projects. The cost for the project was approximately $1.3 billion, according to one source, of which $800 million was for building the CCS process, and the remaining $500 million was for retrofitting the Boundary Dam Unit 3 coal-fired generating unit. The project also received $240 million from the Canadian federal government. Boundary Dam started operating in October 2014, after a four-year construction and retrofit of the 150 megawatt generating unit. The final project was smaller than earlier plans to build a 300 megawatt CCS plant, but that plant may have cost as much as $3.8 billion. The larger-scale project was discontinued because of the escalating costs.

Like the Kemper Plant discussed above, Boundary Dam is a project that sells CO 2 for enhanced oil recovery, shipping 90% of the captured CO 2 via a 41-mile pipeline to the Weyburn Field. Unused CO 2 will be stored in a deep saline aquifer about 2.1 miles underground. The now-operating 110 megawatt (net) plant plans to capture at least 1 million tons of CO 2 per year.

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 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.

It could be argued that in its allocation of Recovery Act funding, DOE was heeding the recommendations of some experts 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: Clean Coal Power Initiative and Industrial Carbon Capture and Storage

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. 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-FY2015). 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."

According to the 2010 DOE CCS Roadmap , Recovery Act funds have been 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." DOE selected six projects under CCPI Round 3 through two separate solicitations. 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 approximately $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 21% to approximately 15%.

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 Megawatt 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 CO 2 per year from a 160 megawatt coal-fired generation unit. 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. Southern Company continues work on a much smaller CCS project that would capture CO 2 from a 25 megawatt unit at Plant Barry.

Basin Electric Power—Antelope Valley 120 Megawatt Project : On July 1, 2009, Secretary Chu announced $100 million in DOE funding for a project that would capture approximately 1 million tons of CO 2 per year from a 120 megawatt electric-equivalent gas stream from the Antelope Valley power station near Beulah, ND. In December 2010, the Basin Electric Power Cooperative withdrew its project from the CCPI program, citing regulatory uncertainty with regard to capturing CO 2 , uncertainty about the project's cost (one source indicates that the company estimated $500 million total cost; DOE estimated $387 million—see Table 2 ), uncertainty of environmental legislation, and lack of a long-term energy strategy for the country. The project would have supplied the captured CO 2 to an existing pipeline that transports CO 2 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 Megawatt Project : In July 2011 American Electric Power (AEP) decided to halt its plans to build a carbon capture plant for a 235 megawatt 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. 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. In addition, company officials cited broader economic and policy conditions as reasons for cancelling the project. Some commentators suggested that congressional inaction on setting limits on GHG emissions, as well as the weak economy, may have diminished the incentives for a company like AEP to invest in CCS. One source concluded that "Phase 2 has been cancelled due to unknown climate policy."

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 award. The remaining funding from the canceled Plant Barry project (up to $154 million) was allotted to the NRG Energy project in Texas (now the Petra Nova Energy Project; see Table 2 ).

According to a DOE source, selection of the Basin Electric Power project was announced but a cooperative agreement was never awarded by DOE. 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. 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.

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 CO 2 . 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. 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 CO 2 . In July 2010, DOE selected six projects from the original 12 projects for a second phase of funding to find ways of converting captured CO 2 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. 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 CO 2 Capture with Increased Efficiencies and Decreased Costs; and (4) Geologic Storage Site Characterization. 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.

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

DOE allocated $112 million in FY2012, $107 million in FY2013, $109 million in FY2014, $100 million in FY2015, and is requesting $109 million in FY2016 for its carbon sequestration and 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 CO 2 storage.

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 CO 2 into subsurface geological reservoirs. Injection and storage is the third step in the CCS process, following the CO 2 capture step and CO 2 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 CO 2 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. The large-volume tests can be considered injection experiments conducted at a commercial scale (i.e., approximately 1 million tons of CO 2 injected per year) that should provide crucial information on the suitability of different geologic reservoirs; monitoring, verification, and accounting of injected CO 2 ; 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. The geographic representation was intended to match regional differences in fossil fuel use and geologic reservoir potential for CO 2 storage. The 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.

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 CO 2 ; (2) Validation Phase (2005 to 2011), small-scale injection field tests (less than 500,000 tons of CO 2 ) to develop a better understanding of how different geologic formations would handle large amounts of injected CO 2 ; and (3) Development Phase (2008 to 2018 and beyond), injection tests of at least 1 million tons of CO 2 to simulate commercial-scale quantities of injected CO 2 . 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 66% of annual spending on carbon sequestration/carbon storage in FY2015, and comprised 58% of that account in the FY2016 budget request. The RCSPs provide 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 CO 2 injection has begun for the SECARB and MGSC projects. 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 CO 2 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 CO 2 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 commercial-scale CCS. These nontechnical issues are not trivial, and could pose serious challenges to widespread deployment of CCS even if the technical challenges of injecting CO 2 safely and in perpetuity are resolved. For example, a complete regulatory framework for managing the underground injection of CO 2 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 CO 2 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.

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 CO 2 , regulation of potential emissions to the atmosphere, legal issues if the CO 2 plume migrates underground across state boundaries, private property rights of owners of the surface lands above the injected CO 2 plume, and ownership of the subsurface reservoirs (also referred to as pore space). 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.

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.

To date, there are no commercial ventures in the United States that capture, transport, and inject large quantities of CO 2 (e.g., 1 million tons per year or more) solely for the purposes of carbon sequestration. The Kemper County Energy project likely will be the first to do so, although the majority of the injected CO 2 will be for purposes of enhanced oil recovery. The Boundary Dam Project in Canada, which began operations in 2014, is the first commercial-scale power plant with CCS in operation in the world. Boundary Dam also sends most of its captured CO 2 to a nearby oilfield for enhanced oil recovery.

The DOE CCS RD&D program has embarked on commercial-scale demonstration projects for CO 2 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 CO 2 from reaching the atmosphere while plants continue to burn fossil fuels, mainly coal. The proposed EPA standard to limit CO 2 emissions from new coal-fired power plants has invited renewed scrutiny of CCS technology and its prospects for commercial deployment. Congress may wish to carefully review the CCS R&D program and particularly the results from the demonstration projects as they progress. Such a review could help Congress evaluate 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 CO 2 . 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.