Globally, two fossil-fueled power plants currently generate electricity and capture CO₂ in large quantities: the Boundary Dam plant in Canada and the Petra Nova plant in Texas. Both plants retrofitted post-combustion capture technology to units of existing plants. A third fossil-fueled electricity-generating operation, the Kemper County Energy Facility in Mississippi, was scheduled to begin CCS operations by now, but cost overruns and delays in construction and operations led to the suspension of the plant's CCS component on June 28, 2017.

Each of the power plants using CCS systems may be referred to as a demonstration project, or a nearly first-of-its-kind venture using technologies developed at a pilot scale ramped up to commercial scale. Such projects move through many phases, from the initial research and development (R&D) phase through the final commercial deployment phase. It is not unusual for projects in the demonstration phase of this process to experience higher-than-anticipated costs, delays, and other challenges. Several other U.S. Department of Energy (DOE)-supported demonstration projects, such as FutureGen, the AEP Mountaineer project, and the Hydrogen Energy California Project, among others, faced challenges that led to their cancellation or suspension. Given the mixed success of large CCS projects in the United States, the economic viability of, and the commercial interest in, such projects remains uncertain.

The U.S. Department of Energy has long supported R&D on CCS within its Fossil Energy Research and Development (FER&D) portfolio. The Trump Administration proposed to cut FER&D funding substantially in its FY2018 budget request. The Trump Administration's proposal differs from the policy trends of the previous two Administrations, which supported R&D on CCS and emphasized the development of large-scale demonstration projects to evaluate how CCS might be deployed commercially. Some in Congress have signaled continued support for DOE's R&D efforts with respect to CCS. The House Energy and Water Development appropriations draft legislation would support CCS R&D at a level comparable to that in FY2017, for example ($635 million versus $668 million enacted for FY2017). The Senate version of the bill would fund FER&D at $573 million in FY2018, $95 million less than in FY2017 but $293 million more than the Administration request. In addition, some Members of Congress have continued to introduce legislation in the 115^th Congress intended to advance CCS. These bills include H.R. 2010, H.R. 2011, H.R. 2296, S. 843, S. 1068, S. 1535, and S. 1663. Two of these bills, S. 1663 and S. 1068, were offered as amendments to tax reform legislation (the Tax Cuts and Jobs Act) under consideration in the Senate Finance Committee.

The Obama Administration commissioned a CCS task force, which concluded in 2010 that the largest barrier to long-term demonstration and deployment of CCS technology is the absence of a federal policy to reduce greenhouse gas emissions. The task force further concluded that widespread deployment of CCS would occur only if the technology is commercially available at economically competitive prices. None of those factors appear to be in place currently, which may indicate that demonstration and deployment of industrial-scale CCS will be delayed compared to earlier projections, pending future policy, technological, and economic developments.

Introduction

Globally, two fossil-fueled power plants currently generate electricity and capture CO₂ in large quantities: the Boundary Dam plant in Canada and the Petra Nova plant. Both plants retrofitted post-combustion capture technology to units of existing plants. (The different types of carbon capture technologies are discussed in "CCS Primer.") A third fossil-fueled electricity-generating operation, the Kemper County Energy Facility, was scheduled to begin CCS operations by now, but cost overruns and delays in construction and operations led to the suspension of the plant's CCS component on June 28, 2017.² Unlike the two retrofitted plants, Kemper was built from scratch with a precombustion integrated gasification combined cycle (IGCC) system. These three plants are discussed below.³

The Petra Nova–W.A. Parish Generating Station is the first industrial-scale coal-fired electricity-generating plant with CCS to operate in the United States. On January 10, 2017, the plant began capturing approximately 5,000 metric tons of CO₂ per day from its 240-megawatt-equivalent slipstream using post-combustion capture technology.⁴ The capture technology is approximately 90% efficient (i.e., it captures about 90% of the CO₂ in the exhaust gas after the coal is burned to generate electricity) and is projected to capture between 1.4 million and 1.6 million tons of CO₂ each year.⁵ The captured CO₂ is transported via an 82-mile pipeline to the West Ranch oil field, where it is injected for enhanced oil recovery (EOR).⁶ NRG Energy, Inc., and JX Nippon Oil & Gas Exploration Corporation, the joint owners of the Petra Nova project, together with Hilcorp Energy Company (which handles the injection and EOR), expect to increase West Ranch oil production from 300 barrels per day before EOR to 15,000 barrels per day after EOR.⁷

DOE provided Petra Nova with more than $160 million from its Clean Coal Power Initiative (CCPI) Round 3 funding, using funds appropriated under the American Recovery and Reinvestment Act of 2009 (Recovery Act; P.L. 111-5) together with other DOE FER&D funding for a total of more than $190 million of federal funds for the $1 billion retrofit project.⁸ Petra Nova is the only CCPI Round 3 project that expended its Recovery Act funding and is currently operating.⁹ The three other CCPI Round 3 demonstration projects funded using Recovery Act appropriations, (as well as the FutureGen project—slated to receive nearly $1 billion in Recovery Act appropriations) all have been canceled, have been suspended, or remain in development.¹⁰

The Petra Nova plant is projected to capture more CO₂ per year than the other currently operating power plant with CCS, Canada's Boundary Dam (which captures about 1 million tons per year; see "Boundary Dam: World's First Addition of CCS to a Large Power Plant," below). Petra Nova also generates more electricity than Boundary Dam, about 240 megawatts compared to Boundary Dam's 115 megawatts. Both projects retrofitted one unit of much larger multi-unit electricity-generating plants. The Petra Nova project retrofitted Unit 8 of the W.A. Parish power plant, which in total consists of four coal-fired units and six gas-fired units, comprising more than 3.7 gigawatts of gross capacity, making it one of the largest U.S. power plants.

In 2015, the entire W.A. Parish complex emitted nearly 15 million tons of CO₂ from all of its generating units.¹¹ The Petra Nova project reduces CO₂ emissions overall from the entire complex by about 11%. By comparison, in 2015, total U.S. CO₂ emissions from the electricity-generating sector were about 1.9 billion tons.¹² The Petra Nova project would reduce that total by a small percentage (about 0.08%). However, according to DOE, a purpose of Petra Nova was to demonstrate that post-combustion capture and reuse can be done economically for existing plants when there is an opportunity to recover oil from nearby oilfields. DOE also has stated that the success of Petra Nova has the potential to enhance the long-term viability and sustainability of coal-fueled power plants across the United States and throughout the world.¹³

On June 28, 2017, Southern Company and its subsidiary Mississippi Power announced they were suspending the start-up of the coal gasification component of their Kemper County Energy Facility,¹⁴ a precombustion technology that would combine IGCC with CCS to capture CO₂ and transport the gas for EOR at a nearby oilfield. The suspension of operations comes after several years of cost overruns and delays; total costs escalated to more than $7 billion from approximately $2.67 billion, and the original target start-up date was 2014.¹⁵ The plant will continue to generate electricity from burning natural gas, according to Southern Company, pending a decision from the Mississippi Public Service Commission on future operations.¹⁶

DOE supported the Kemper County plant with a $270 million award for the development and deployment of a gasification technology called Transport Integrated Gasification (TRIG^TM), under a cooperative agreement as part of the CCPI Round 2 program. The $270 million award represented approximately 10% of what DOE had reported as the overall cost to build the plant, approximately $2 billion.¹⁷ At the time of the award, the plant was expected to have an estimated peak net output capability of 582 megawatts and was designed to capture 65% of the total CO₂ emissions released.¹⁸ According to DOE, that would have made the CO₂ emissions from the Kemper project comparable to emissions from a natural gas-fired combined cycle power plant. The estimated 3 million tons of CO₂ captured each year from the plant were to be transported via pipeline for use in EOR operations at nearby depleted oil fields in Mississippi.

The Mississippi Public Service Commission approved the project, subject to a cap on total costs of $2.9 billion.¹⁹ Construction began in 2010.²⁰ Some observers attribute the cost escalation and project delays to a combination of increased piping, materials, and labor costs due to resizing and re-scoping of the original design of the CCS component.²¹ In addition, Kemper's status as a first-of-its kind facility likely contributed to cost overruns and construction delays.

Suspension of the Kemper County plant increases uncertainty about the future of large CCS projects at coal-fired power plants in the United States and, by extension, into the future of coal. Kemper is not the first large, DOE-supported CCS demonstration project to hit roadblocks leading to delay and even cancellation.²² The Trump Administration has signaled that it will not support large CCS demonstration projects in its FY2018 budget request, proposing to substantially reduce CCS funding and refocus its entire FER&D portfolio on "early-stage" research.²³ The House Appropriations Committee's FY2018 bill funding DOE disagrees with the Administration budget request and would fund CCS activities at roughly FY2017 levels. However, suspension of the Kemper County Energy Facility might affect budget negotiations if, as some CCS critics suggest, it signals a deeper problem with the viability of CCS at fossil-fuel-burning power plants generally.²⁴

The Boundary Dam project was the first commercial-scale power plant with CCS in the world to begin operations. Boundary Dam, a Canadian venture operated by SaskPower,²⁵ cost approximately $1.3 billion according to one source.²⁶ Of that amount, $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 original idea may have cost as much as $3.8 billion. The larger-scale project was discontinued because of the escalating costs.²⁷

Similar to the Petra Nova project discussed above, Boundary Dam captures, transports, and sells most of its CO₂ for enhanced oil recovery, shipping 90% of the captured CO₂ via a 41-mile pipeline to the Weyburn Field. CO₂ not sold for EOR is injected and stored about 2.1 miles underground in a deep saline aquifer at a nearby experimental injection site. By March 2017, the plant had captured almost 1.5 million metric tons of CO₂ since full-time operations began in October 2014.²⁸ The 115-megawatt (net) plant plans to capture at least 1 million tons of CO₂ per year.²⁹

Some observers contend that Boundary Dam has yet to meet its expectations for capture efficiency, cost, and availability.³⁰ Some technical and operational issues that reduced the amount of CO₂ captured after start-up were reported in 2016, and these issues led to shortfalls in delivery of CO₂ to the utility using the gas for EOR.³¹ Some reports also indicated that the CCS system consumed approximately 45 megawatts to capture and compress the CO₂,³² out of a total capacity of 150 megawatts (approximately 30% reduction, also known as the energy penalty or parasitic load).

In recent years, the DOE CCS program (discussed below) has emphasized commercial-scale demonstration projects to better estimate the future costs and technical challenges for CCS. Some CCS critics contend that the gap in time and cost between the "first of a kind" project, such as the three discussed above, and the "N^th of a kind" project—representing projects at the commercial deployment stage—could be decades away and require hundreds of billions of dollars in capital investment.³³ Such speculations, however, are highly uncertain, given the possible changes in U.S. and other countries' policies aimed at restricting carbon emissions, as well as technological development, the cost of competing fuels such as natural gas, and other factors. Nevertheless, with the recent suspension of the Kemper project, a near-term estimate of the economic viability of—or even interest in—new, commercial-scale electricity-generating plants with CCS in the United States remains uncertain.

The Senate and the House have seen bills introduced in the last several Congresses that would have tried to foster or shape CCS development in the United States. This trend has continued in the 115^th Congress; several bills have been introduced that would address aspects of CCS. These bills are summarized briefly below.

S. 1535 would amend Section 45(Q) of the Internal Revenue Code to increase the tax credit from $20 per ton to $50 per ton for capture and permanent storage of CO₂ and from $10 per ton to $35 per ton for capture and use of CO₂ for EOR. The tax credit amount would ramp up over a 12-year period through 2025, increasing by an inflation factor after that. In addition to CO₂ captured from facilities such as power plants and oil refineries, the credit would be available for facilities that capture CO₂ directly from the atmosphere (direct air capture). The tax credit also would be available for utilization of CO₂, such as through bacteria or algae growth or the conversion of CO₂ into a solid material. Facilities and processes that use CO₂ to make materials or otherwise use CO₂ for any other purpose for which a commercial market exists (other than EOR) through utilization would be eligible for the tax credit.

S. 1068 would make available an investment tax credit for qualified CCS equipment that is installed at an electricity-producing facility and captures at least 50% of the CO₂ emissions at the facility that otherwise would have been emitted to the atmosphere. To qualify, the captured CO₂ would need to be disposed of in secure geological storage.³⁴

H.R. 2011 and S. 843 would make carbon capture facilities eligible for tax-exempt bonds by amending Section 142 of the Internal Revenue Code. The CCS facility components would be eligible for the tax-exempt bond if the facility captures and stores at least 65% of the CO₂ that otherwise would be emitted to the atmosphere. If the facility captures and stores less than 65% of the CO₂, the percentage of the cost of CCS components eligible for tax-exempt bonds could not be greater than the capture and storage percentage (i.e., if the facility captures and stores 50% of the CO₂, then 50% of the cost of the components would be eligible for the tax-exempt bond).

H.R. 2296 would require the Secretary of Energy to conduct an annual evaluation of every CCS-related project that uses DOE funds for research, development, demonstration, or deployment of CCS technologies (including CO₂ utilization technologies).³⁵ The bill would require the Secretary to determine if the project—whether under contract, lease, cooperative agreement, or other similar transaction with a public agency, private organization, or person—has made significant progress in advancing a CCS technology. Based on the determination of whether progress has been made, the Secretary would make a recommendation to increase funding or would determine that the project has reached its full potential and recommend whether the project should continue. The Secretary would be required to report on the recommendations and make the report available to the public, the Senate Committee on Energy and Natural Resources, and the House Committee on Energy and Commerce's Subcommittee on Energy.

H.R. 2010 and S. 1663 would amend Section 45Q(d) of the Internal Revenue Code to require that the Secretary of the Treasury, in consultation with the Secretaries of Energy and the Interior and the Administrator of the Environmental Protection Agency (EPA), establish regulations for the geological storage of CO₂. Those regulations would determine compliance for both CO₂ injected for EOR purposes and CO₂ injected for non-EOR purposes (i.e., permanent geological sequestration). For CO₂ injected for EOR purposes, the bill would consider the CO₂ disposed of (in secure geological storage) if it is stored in compliance with the rules promulgated by the EPA under subpart UU of 40 C.F.R. Part 98, under the Clean Air Act, and subpart C of 40 C.F.R. Part 146, under the Safe Drinking Water Act, to the extent the rules apply to Class II wells.³⁶

On November 13, 2017, the Senate Committee on Finance began considering legislation entitled the Tax Cuts and Jobs Act, which would make changes to the U.S. tax code. Amendments offered to the legislation include S. 1663, as introduced by Senator Hoeven (amendment offered by Senator Hatch), and S. 1068, the Clean Energy for America Act (amendment offered by Senator Wyden). The tax reform bill being considered in the House, H.R. 1, was reported from the House Ways and Means Committee on November 9, 2017, but did not contain any provisions to use the tax code for CCS that are under consideration in the Senate.

DOE has funded R&D of aspects of the three main steps leading to an integrated CCS system since 1997. Since FY2010, Congress has provided more than $4.3 billion in annual appropriations for CCS activities at DOE. The Recovery Act provided an additional $3.4 billion to that total.³⁷

CCS-focused R&D has come to dominate the coal program area within DOE FER&D since 2010. The Trump Administration's FY2018 budget request, however, would cut the overall FER&D budget by more than half compared to FY2017. The budget request also would reduce CCS-related activities substantially and would refocus nearly the entire R&D portfolio toward "early-stage" research.³⁸ The Trump Administration's approach would be a reversal of Obama Administration and George W. Bush Administration DOE policies, which supported large carbon-capture demonstration projects and large injection and sequestration demonstration projects.

The transport and injection/storage steps of the CCS process are not technologically challenging per se, as compared to the capture step. Carbon dioxide pipelines are in use for EOR in regions of the United States today, and large quantities of fluids have been injected into the deep subsurface for a variety of purposes for decades, such as disposal of wastewater from oil and gas operations or of municipal wastewater. However, the transport and capture steps still face challenges, including economic and regulatory issues, rights-of-way, and questions regarding the permanence of CO₂ sequestration in deep geological reservoirs, as well as ownership and liability for the stored CO₂, among others.

The first step in CCS is to capture CO₂ at the source, compress it, and produce a concentrated stream for transport and storage. Currently, three main approaches are available to capture CO₂ from large-scale industrial facilities or power plants: (1) post-combustion capture, (2) precombustion capture, and (3) oxy-fuel combustion capture. For power plants, current commercial CO₂ capture systems could operate at 85%-95% capture efficiency.⁴⁰ In a worst-case scenario, the capture phase of the CCS process may increase the cost of electricity by 80% and reduce an electricity-generating plant's net capacity by 20%.⁴¹ Further, as much as 70%-90% of the total cost for CCS is associated with the capture and compression phase of CCS.⁴² Other estimates indicate that the energy penalty could be much lower, resulting in smaller impacts to subsequent electricity costs.⁴³ A detailed description and assessment of these capture technologies is provided in CRS Report R41325, Carbon Capture: A Technology Assessment, by [author name scrubbed].

The process of post-combustion capture involves extracting CO₂ from the flue gas following combustion of fossil fuels or biomass.⁴⁴ Several commercially available technologies, some involving absorption using chemical solvents, can in principle be used to capture large quantities of CO₂ from flue gases. Other than the Petra Nova plant, discussed above, no large U.S. commercial electricity-generating plants currently capture large volumes of CO₂. As the Petra Nova project indicates, the post-combustion capture process includes proven technologies that are commercially available today.

The process of precombustion capture separates CO₂ from the fuel by combining the fuel with air and/or steam to produce hydrogen for combustion and a separate CO₂ stream that could be stored. The most common technologies today use steam reforming, in which steam is employed to extract hydrogen from natural gas.⁴⁵ One example of precombustion capture technology in operation today is at the Great Plains Synfuels Plant in Beulah, ND. The Great Plains plant produces synthetic natural gas from lignite coal through a gasification process, and the natural gas is shipped out of the facility for sale in the natural gas market. The process also produces a stream of high-purity CO₂, which is piped northward into Canada for use in EOR at the Weyburn oil field.⁴⁶

The process of oxy-fuel combustion capture uses oxygen instead of air for combustion and produces a flue gas that is mostly CO₂ and water, which are easily separable, after which the CO₂ can be compressed, transported, and stored.

Pipelines are the most common method for transporting CO₂ in the United States. Currently, approximately 4,500 miles of pipelines transport CO₂ in the United States, predominately to oil fields, where it is used for EOR.⁴⁷ Transporting CO₂ in pipelines is similar to transporting fuels such as natural gas and oil; it requires attention to design, monitoring for leaks, and protection against overpressure, especially in populated areas.⁴⁸ Typically, CO₂ would be compressed prior to transportation, making it dense like a liquid but fluid like a gas.⁴⁹

Using ships may be feasible when CO₂ must be transported over large distances or overseas. Ships transport CO₂ today, but at a small scale because of limited demand. Liquefied natural gas, propane, and butane are routinely shipped by marine tankers on a large scale worldwide. Rail cars and trucks also can transport CO₂, but this mode probably would be uneconomical for large-scale CCS operations.

Costs for pipeline transport vary, depending on construction, operation and maintenance, and other factors, including right-of-way costs, regulatory fees, and more. The quantity and distance transported will mostly determine costs, which also will depend on whether the pipeline is onshore or offshore; the level of congestion along the route; and whether mountains, large rivers, or frozen ground are encountered. Shipping costs are unknown in any detail, because no large-scale CO₂ transport system via ship (in millions of tons of CO₂ per year, for example) is operating. Ship costs might be lower than pipeline transport for distances greater than 1,000 kilometers and for less than a few million tons of CO₂ transported per year.⁵⁰

Even though regional CO₂ pipeline networks currently operate in the United States for EOR, developing a more expansive network for CCS could pose regulatory and economic challenges. Some observers note that development of a national CO₂ pipeline network that would address the broader issue of greenhouse gas reduction using CCS may require a concerted federal policy beyond the current joint federal-state regulatory policy.⁵¹ One recommendation is for federal regulators to build on state experience for siting CO₂ pipelines, for example.

Three main types of geological formations are being considered for carbon sequestration: (1) depleted oil and gas reservoirs, (2) deep saline reservoirs, and (3) unmineable coal seams. In each case, CO₂ would be injected in a supercritical state—a relatively dense liquid—below ground into a porous rock formation that holds or previously held fluids. When CO₂ is injected at depths greater than 800 meters in a typical reservoir, the pressure keeps the injected CO₂ in a supercritical state (dense like a liquid, fluid like a gas), making the CO₂ less likely to migrate out of the geological formation. Injecting CO₂ into deep geological formations uses existing technologies that have been primarily developed and used by the oil and gas industry and that potentially could be adapted for long-term storage and monitoring of CO₂.

DOE's Regional Carbon Sequestration Partnership Initiative has been actively pursuing a three-phase approach to the sequestration step in the CCS process since 2003. It is currently in the development phase.⁵² The development phase includes implementation of large-scale field testing of approximately 1 million tons of CO₂ per project to confirm the safety, permanence, and economics of industrial-scale CO₂ storage in seven different regions of the United States.⁵³ The development phase began in 2008 and is projected to last to 2018 or beyond.

Pumping CO₂ into oil and gas reservoirs to boost production (that is, enhanced oil recovery) is practiced in the petroleum industry today. The United States is a world leader in this technology, and oil and gas operators inject approximately 68 million tons of CO₂ underground each year to help recover oil and gas resources.⁵⁵ Most of the CO₂ used for EOR in the United States comes from naturally occurring geologic formations, however, not from industrial sources. Using CO₂ from industrial emitters has appeal because the costs of capture and transport from the facility could be partially offset by revenues from oil and gas production. Both of the currently operating large electricity-generating plants with CCS, Boundary Dam and Petra Nova, offset some of the costs of CCS by selling the captured CO₂ for EOR.

Carbon dioxide can be used for EOR onshore or offshore. To date, most CO₂ projects associated with EOR are onshore, with the bulk of U.S. activities in western Texas.⁵⁶ Carbon dioxide also can be injected into oil and gas reservoirs that are completely depleted, which would serve the purpose of long-term sequestration but without any offsetting benefit from oil and gas production.

U.S. coal resources that are not mineable with current technology are those in which the coal beds are not thick enough, are too deep, or lack structural integrity adequate for mining.⁵⁸ Even if they cannot be mined, coal beds are commonly permeable and can trap gases, such as methane, which can be extracted (a resource known as coal-bed methane, or CBM). Methane and other gases are physically bound (adsorbed) to the coal. Studies indicate that CO₂ binds to coal even more tightly than methane binds to coal.⁵⁹ CO₂ injected into permeable coal seams could displace methane, which could be recovered by wells and brought to the surface, providing a source of revenue to offset the costs of CO₂ injection. Unlike EOR, injecting CO₂ and displacing, capturing, and selling CBM (a process known as enhanced coal bed methane recovery) to offset the costs of CCS is not yet part of commercial production. Currently, nearly all CBM is produced by removing the water trapped in the coal seam, which reduces the pressure and enables the release of the methane gas from the coal.

Many CCS proponents hailed the start-up of the first U.S. coal-fired power plant with CCS—Petra Nova—as a major step in the advancement of CCS deployment across the electricity sector and a milestone for CCS as a viable technology for reducing greenhouse gas emissions.⁶⁰ The enthusiasm for Petra Nova may have been tempered somewhat by the June 28, 2017, announcement that Mississippi Power was suspending the CCS portion of its Kemper County Energy Facility. Kemper is a long-anticipated project with combined coal gasification and CCS using technology developed with assistance from DOE. Unlike Petra Nova and the Boundary Dam CCS plant in Canada—both retrofits of older plants—Kemper was built with the intention to integrate CCS technology into the plant design from the outset. All three plants received subsidies from the federal government, but other factors were at play in determining the success or failure of each venture.

In some aspects, the Kemper plant resembled the original design for the FutureGen plant during the George W. Bush Administration: a power plant built from scratch to be largely emissions free using CCS.⁶¹ Cost issues and schedule delays also hampered FutureGen, even though it was slated to receive nearly $1 billion in federal funds, far more than the amount provided to Kemper.

Costs and schedule delays for nearly first-of-a-kind large, capital-intensive projects are not unanticipated, as demonstration phase projects commonly fall along the most expensive part of a cost curve from inception to commercial deployment. Nevertheless, the mixed success in 2017 of the Petra Nova and Kemper plants puts the further development of CCS somewhat at a crossroads, particularly with the apparent lack of interest in further support for such projects signaled by the Trump Administration. President Trump's FY2018 budget request would severely reduce DOE funding for CCS overall. In addition, the Administration has expressed interest in supporting early-stage research within its FER&D portfolio but not in supporting large demonstration-scale projects such as Petra Nova or Kemper.

The Obama Administration commissioned a CCS task force, which concluded that the largest barrier to long-term demonstration and deployment of CCS technology is the absence of a federal policy to reduce greenhouse gas emissions.⁶² The task force further concluded that widespread deployment of CCS will occur only if the technology is commercially available at economically competitive prices. None of those factors appear to be in place currently, which may indicate that demonstration and deployment of industrial-scale CCS will be delayed compared to earlier projections, pending future policy, technological, and economic developments.

Even with the current uncertainty over the future of CCS, some in Congress have signaled continued support for DOE's R&D efforts with respect to CCS. The House Energy and Water Development appropriations draft legislation would support CCS R&D at a level comparable to FY2017, for example.⁶³ The Senate version of the appropriations legislation would fund CCS R&D at a lower level than the House version but a far higher level than the Administration's budget request. In addition, some Senators and Members of Congress have continued to introduce legislation in the 115^th Congress intended to advance and shape CCS.

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Footnotes