CRS Releases Report on U.S. Carbon Capture, Sequestration

Carbon Capture and Sequestration (CCS) in the United States

Peter Folger
Specialist in Energy and Natural Resources Policy

August 9, 2018

Congressional Research Service
7-5700
www.crs.gov
R44902

Summary

Carbon capture and sequestration (or storage) — known as CCS — is a process that involves capturing man-made carbon dioxide (CO₂) at its source and storing it permanently underground. (CCS is sometimes referred to as CCUS — carbon capture, utilization, and storage.) CCS could reduce the amount of CO₂ — an important greenhouse gas — emitted to the atmosphere from the burning of fossil fuels at power plants and other large industrial facilities. The concept of carbon utilization has gained interest within Congress and in the private sector as a means for capturing CO₂ and converting it into potentially commercially viable products, such as chemicals, fuels, cements, and plastics, thereby reducing emissions to the atmosphere and helping offset the cost of CO₂ capture. Direct air capture is also an emerging technology, with the promise to remove atmospheric CO₂ directly and reduce its concentration.

The U.S. Department of Energy (DOE) has funded research and development (R&D) of aspects of CCS since 1997 within its Fossil Energy Research and Development (FER&D) portfolio. Since FY2010, Congress has provided more than $5 billion total in appropriations for DOE CCS-related activities. The Trump Administration proposed to reduce FER&D funding substantially in its FY2018 and FY2019 budget requests, but Congress has not agreed to the proposed reductions. In FY2018, Congress increased funding for DOE FER&D by nearly $59 million (9%) compared to FY2017, and the House- and Senate-passed appropriations bills for FY2019 would match or increase the appropriated amount compared to what Congress enacted for FY2018 ($727 million).

The Petra Nova plant in Texas is the only U.S. fossil-fueled power plant currently generating electricity and capturing CO₂ in large quantities (over 1 million tons per year). Globally, the Boundary Dam plant in Canada is the only other large-scale fossil-fueled power plant with CCS. Both facilities retrofitted post-combustion capture technology to units of existing plants, and both offset a portion of the cost of CCS by selling captured CO₂ for the purpose of enhanced oil recovery (EOR). Some CCS proponents point to the expanded Section 45Q of the Internal Revenue Code tax credits for CO₂ capture and sequestration or its use as a tertiary injectant for EOR or natural gas production that were enacted as part of P.L. 115-123 as a significant step toward incentivizing more development of large-scale CCS deployment like Petra Nova and Boundary Dam.

A number of bills introduced in the 115^th Congress potentially would affect CCS in the United States. Several bills or provisions of bills address the Section 45Q tax credits (S. 1535, S. 1663, S. 2256, H.R. 1892, H.R. 2010, H.R. 3761, H.R. 4857). H.R. 1892, the Bipartisan Budget Act of 2018, enacted into law as P.L. 115-123, amended Section 45Q and increased the amount of the tax credit from $20 to $50 per ton of CO₂ for permanent sequestration, increased it from $10 to $35 for EOR purposes, and effectively removed the 75 million ton cap on the total amount of CO₂ injected underground, among other changes. Some proponents suggest that enactment of this provision could be a “game changer” for CCS, leading to more widespread adoption of the technology, although others question whether the increased incentives are large enough to affect CCS deployment.

Other bills address a suite of measures to advance CCS. Several would provide additional financial incentives, such as tax-exempt private activity bonds, and provisions that would enable eligibility of master limited partnerships for CCS infrastructure projects (S. 843, S. 2005, H.R. 2011, and H.R. 4118). One bill (S. 2602) could help advance CCS by making CCS infrastructure projects eligible under the FAST Act (42 U.S.C. 4370m(6)). Other bills (S. 2803, S. 2997, H.R. 2296, H.R. 5745) would support increased R&D for CCS, carbon utilization technologies, and direct air capture of CO₂. One bill (H.R. 4096) would authorize a $5 million prize to promote advances in CCS technology research and development.

There is broad agreement that costs for CCS would need to decrease before the technologies could be deployed commercially across the nation. The issue of greater CCS deployment is fundamental to the underlying reason CCS is deemed important by a range of proponents: to reduce CO₂ emissions (or reduce the concentration of CO₂ in the atmosphere) and to help mitigate against human-induced climate change.

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Contents

CCS Primer

Coal-Fired Power Plants with CCS

The DOE CCS Program

CCS-Related Legislation in the 115^th Congress

Discussion

Figures

Figure 1. The CCS Process

Figure 2. Diagram of Post-Combustion CO₂ Capture in a Coal-Fired Power Plant Using an Amine Scrubber System

Figure 3. Diagram of Precombustion CO₂ Capture from an IGCC Power Plant

Figure 4. Diagram of Oxy-Combustion CO₂ Capture from a Coal-Fired Power Plant

Figure 5. Schematic Illustration of Current and Potential Uses of CO₂

Tables

Table 1. Estimates of the U.S. Storage Capacity for CO₂

Table 2. Funding for DOE Fossil Energy Research, Development, and Demonstration Program Areas

Table A-1. CCS-Related Legislation in the 115^th Congress

Contacts

Author Contact Information

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Carbon capture and sequestration (or storage) — known as CCS — is a process that involves capturing man-made carbon dioxide (CO₂) at its source and storing it to avoid its release to the atmosphere. (CCS is sometimes referred to as CCUS — carbon capture, utilization, and storage.) CCS could reduce the amount of CO₂ emitted to the atmosphere from the burning of fossil fuels at power plants and other large industrial facilities.¹ An integrated CCS system would include three main steps: (1) capturing and separating CO₂ from other gases; (2) purifying, compressing, and transporting the captured CO₂ to the sequestration site; and (3) injecting the CO₂ in underground geological reservoirs (the process is explained more fully below in “CCS Primer”). In recent years, utilization as part of CCUS increasingly has been viewed as a potentially important component of the process. Utilization refers to the beneficial use of CO₂ as a means of mitigating CO₂ emissions and converting it to chemicals, cements, plastics, and other products.² (This report uses the term CCS except in cases where utilization is specifically discussed.)

The U.S. Department of Energy (DOE) has long supported research and development (R&D) on CCS within its Fossil Energy Research and Development portfolio (FER&D). Since FY2010, Congress has provided more than $5 billion in total appropriations for CCS activities within DOE FER&D (not including the one-time appropriation of $3.4 billion provided for CCS in the American Recovery and Reinvestment Act of 2009, P.L. 111-5).

In its FY2018 and FY2019 budget requests, the Trump Administration proposed to reduce FER&D funding compared to previous years. 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 — nearly first-of-their-kind ventures using technologies developed at a pilot or smaller scale that have been ramped up to commercial scale — to evaluate how CCS might be deployed commercially.

Congress did not accept the Administration's FY2018 request for DOE FER&D and instead increased funding by nearly $59 million (9%) compared to FY2017. In 2018 Congress also enacted legislation (Title II, Section 4119 of P.L. 115-123) that would increase the tax credit for capturing and sequestering or utilizing CO₂, leading many observers to predict increased CCS activity as a result.

This report includes a primer on the CCS (and carbon utilization) process and discusses the current state of CCS in the United States, as well as the DOE program for CCS R&D and CCS-related legislation in the 115^th Congress.

CCS Primer

An integrated CCS system would include three main steps: (1) capturing and separating CO₂ from other gases; (2) purifying, compressing, and transporting the captured CO₂ to the sequestration site; and (3) injecting the CO₂ in subsurface geological reservoirs. The most technologically challenging and costly step in the process is the capture step, which is capital-intensive to build and requires a considerable amount of energy to operate (the amount of energy a power plant uses to capture and compress CO₂ is that much less electricity the plant can deliver to its customers; this is sometimes referred to as the energy penalty or the parasitic load). Figure 1 shows the CCS process schematically from source to storage.

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.

CO₂ Capture

The first step in CCS is to capture CO₂ at the source and separate it from other gases. 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 theoretically could operate at 85%-95% capture efficiency — meaning that 85% to 95% of all the CO₂ produced during the combustion process could be captured before it goes up the stack into the atmosphere.³

In a worst-case scenario, energy penalty in 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%.⁴ Further, as much as 70%-90% of the total cost for CCS is associated with the capture and compression phases of CCS.⁵ Other estimates indicate that the energy penalty could be lower, resulting in smaller impacts to subsequent electricity costs.⁶ A detailed description and assessment of these capture technologies is provided in CRS Report R41325, Carbon Capture: A Technology Assessment, by Peter Folger.

Post-combustion Capture

The process of post-combustion capture involves extracting CO₂ from the flue gas — the mix of gases produced that goes up the exhaust stack — following combustion of fossil fuels or biomass.⁷ Several commercially available technologies, some involving absorption using chemical solvents (such as an amine, see Figure 2), can in principle be used to capture large quantities of CO₂ from flue gases.⁸ In a vessel called an absorber, the flue gas is “scrubbed” with an amine solution, typically capturing 85% to 90% of the CO₂. The CO₂-laden solvent is then pumped to a second vessel, called a regenerator, where heat is applied (in the form of steam) to release the CO₂. The resulting stream of concentrated CO₂ is then compressed and piped to a storage site, while the depleted solvent is recycled back to the absorber.

Other than the Petra Nova plant (discussed in “Petra Nova: The First (and Only) Large U.S. Power Plant with CCS”), no large U.S. commercial electricity-generating plants currently capture large volumes of CO₂ (i.e., over 1 million tons per year). As the Petra Nova project indicates, the post-combustion capture process includes proven technologies that are commercially available today.

Precombustion Capture

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. For coal-fueled plants, this is accomplished by reacting coal with steam and oxygen at high temperature and pressure, a process called partial oxidation, or gasification (Figure 3).⁹ The result is a gaseous fuel consisting mainly of carbon monoxide and hydrogen — a mixture known as synthesis gas, or syngas — which can be burned to generate electricity. After particulate impurities are removed from the syngas, a two-stage “shift reactor” converts the carbon monoxide to CO₂ via a reaction with steam (H2O). The result is a mixture of CO₂ and hydrogen. A chemical solvent, such as the widely used commercial product Selexol (which employs a glycol-based solvent), then captures the CO₂, leaving a stream of nearly pure hydrogen that is burned in a combined cycle power plant to generate electricity — this is known as an integrated gasification combined-cycle plant (IGCC) — as depicted in Figure 3.

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 enhanced oil recovery (EOR)¹⁰ at the Weyburn oil field.¹¹

Oxy-Fuel Combustion Capture

The process of oxy-fuel combustion capture uses pure 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 (Figure 4). Oxy-fuel combustion requires an oxygen production step, which would likely involve a cryogenic process (shown as the air separation unit in Figure 4). The advantage of using pure oxygen is that it eliminates the large amount of nitrogen in the flue gas stream.¹²

Currently oxy-fuel combustion projects are at the lab- or bench-scale ranging up to verification testing at a pilot scale.¹³

CO₂ Transport

After the CO₂ capture step, the gas is purified and compressed to produce a concentrated stream for transport. 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,¹⁴ where it is used for EOR. 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.¹⁵ Typically, CO₂ would be compressed prior to transportation into a supercritical state,¹⁶ making it dense like a liquid but fluid like a gas.

Using ships may be feasible when CO₂ must be transported over large distances or overseas. Liquefied natural gas, propane, and butane are routinely shipped by marine tankers on a large scale worldwide. Ships transport CO₂ today, but at a small scale because of limited demand. 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.¹⁷ 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.¹⁸

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.¹⁹ One recommendation from stakeholders is for federal regulators to build on state experience for siting CO₂ pipelines, for example.²⁰

CO₂ Sequestration

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 fluid — below ground into a porous rock formation that holds or previously held fluids (Figure 1). When CO₂ is injected at depths greater than about half a mile (800 meters) in a typical reservoir, the pressure keeps the injected CO₂ supercritical, making the CO₂ less likely to migrate out of the geological formation. The process also requires that the geological formation have an overlying caprock or relatively impermeable formation, such as shale, so that injected CO₂ remains trapped underground (Figure 1). 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.²¹ 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.²² The development phase began in 2008 and is projected to last through 2018 and possibly beyond.

The storage capacity for CO₂ in geological formations is potentially huge if all the sedimentary basins in the world are considered.²³ In the United States alone, DOE has estimated the total storage capacity to range between about 2.6 trillion and 22 trillion tons of CO₂ (see Table 1).²⁴

The suitability of any particular site, however, depends on many factors, including proximity to CO₂ sources and other reservoir-specific qualities such as porosity, permeability, and potential for leakage.²⁵ For CCS to succeed, it is assumed that each reservoir type would permanently store the vast majority of injected CO₂, keeping the gas isolated from the atmosphere in perpetuity. That assumption is untested, although part of the DOE CCS R&D program has been devoted to experimenting and modeling the behavior of large quantities of injected CO₂. Theoretically — and without consideration of costs, regulatory issues, public acceptance, infrastructure needs, liability, ownership, and other issues — the United States could store its total CO₂ emissions from large stationary sources (at the current rate of emissions) for centuries.

Oil and Gas Reservoirs

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.²⁶ 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 (discussed below in “Coal-Fired Power Plants with CCS”), offset some of the costs by selling the captured CO₂ for EOR.

Carbon dioxide can be used for EOR onshore or offshore. To date, most U.S. CO₂ projects associated with EOR are onshore, with the bulk of activities in western Texas.²⁷ 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.

Deep Saline Reservoirs

Some rocks in sedimentary basins contain saline fluids — brines or brackish water unsuitable for agriculture or drinking. As with oil and gas, deep saline reservoirs can be found onshore and offshore; they are often part of oil and gas reservoirs and share many characteristics. The oil industry routinely injects brines recovered during oil production into saline reservoirs for disposal.²⁸ As Table 1 shows, deep saline reservoirs constitute the largest potential for storing CO₂ by far. However, unlike oil and gas reservoirs, storing CO₂ in deep saline reservoirs does not have the potential to enhance the production of oil and gas or to offset costs of CCS with revenues from the produced oil and gas.

Unmineable Coal Seams

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.²⁹ 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.³⁰ 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, or ECBM) to offset the costs of CCS is not yet part of commercial production. Currently, nearly all CBM is produced by removing water trapped in the coal seam, which reduces the pressure and enables the release of the methane gas from the coal.

Carbon Utilization

The concept of carbon utilization has gained increasingly widespread interest within Congress and in the private sector as a means for capturing CO₂ and storing it in potentially useful and commercially viable products, thereby reducing emissions to the atmosphere, and for offsetting the cost of CO₂ capture. The carbon utilization process is often referred to in legislative language and elsewhere as CCUS.³¹ (See, for example, S. 2803, S. 2997, H.R. 2296, discussed below in “CCS-Related Legislation in the 115th Congress.”)

P.L. 115-123, the Bipartisan Budget Act of 2018, defines carbon utilization as

• the fixation of such qualified carbon oxide through photosynthesis or chemosynthesis, such as through the growing of algae of bacteria;

• the chemical conversion of such qualified carbon oxide to a material or chemical compound in which such qualified carbon oxide is securely stored; and

• the use of such qualified carbon oxide for any other purpose for which a commercial market exists (with the exception of use as a tertiary injectant in a qualified enhanced oil or natural gas recovery project), as determined by the Secretary [of the Treasury].³²

Figure 2 illustrates an array of potential utilization pathways ranging from food and fuels to solid building materials like cement to fertilizers. DOE notes that many of the uses shown in Figure 2 are small scale and typically emit the CO₂ back to the atmosphere after use, negating the initial reduction in overall CO₂ emissions.³³ DOE sponsors research to develop technologies capable of manufacturing stable products using CO₂ and storing it in a form that will not escape to the atmosphere. The four main areas of DOE-sponsored research in this area are for (1) cement; (2) polycarbonate plastics; (3) mineralization (conversion of CO₂ to carbonates); and (4) enhanced oil (EOR) and gas recovery.³⁴ Using CO₂ for EOR currently dominates the estimated 80 million tons of CO₂ used worldwide,³⁵ and CCUS proponents indicate that EOR likely will continue as the dominant use in the short to medium term.³⁶

Direct Air Capture

Direct air capture (DAC) is an emerging set of technologies that aims to remove CO₂ directly from the atmosphere, as opposed to the point source capture of CO₂ from a source like a power plant (as described above in “CO2 Capture”).

DAC systems typically employ a chemical capture system to separate CO₂ from ambient air, addition of energy to separate the captured CO₂ from the chemical substrate, and removal of the purified CO₂ to be stored permanently or utilized for other purposes (Figure 5).³⁷

DAC systems have the potential to be classified as net carbon negative, meaning that if the captured CO₂ is permanently sequestered or becomes part of long-lasting products such as cement or plastics, the end result would be a reduction in the atmospheric concentration of CO₂. In addition, DAC systems can be sited almost anywhere, they do not need to be near power plants or other point sources of CO₂ emissions. They could be located, for example, close to manufacturing plants that require CO₂ as an input, and wouldn't need long pipeline systems to transport the captured CO₂.

The concentration of CO₂ in ambient air is far lower than the concentration found at most point sources. Thus, a recognized drawback of DAC systems is their high cost per ton of CO₂ captured, compared to the more conventional CCS technologies.³⁸ A 2011 assessment estimated costs at roughly $600 per ton of captured CO₂.³⁹ A more recent assessment from one of the companies developing DAC technology, however, projects lower costs for commercially deployed plants between $94 and $232 per ton.⁴⁰ By comparison, some estimate costs for conventional CCS from coal-fired electricity generating plants in the United States between $48 and $109 per ton.⁴¹

Legislation introduced in the 115^th Congress, S. 2602 (the USE IT Act, see Table 2), includes the purpose “to support carbon dioxide utilization and direct air capture research” among other purposes, and contains language for a technology prize that would be awarded for DAC projects that capture more than 10,000 tons per year at a cost of less than $200 per ton CO₂ captured. H.R. 4096, the Carbon Capture Prize Act, would offer a prize for technology developed to reduce the amount of CO₂ in the atmosphere, which would include DAC technologies.

Coal-Fired Power Plants with CCS

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. (The different types of carbon capture technologies are discussed above in “CCS Primer.”)

Petra Nova: The First (and Only) Large U.S. Power Plant with CCS

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 tons of CO₂ per day from its 240-megawatt-equivalent slipstream using post-combustion capture technology.⁴² 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.⁴³ 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). 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.⁴⁴

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.⁴⁵ Petra Nova is the only CCPI Round 3 project that expended its Recovery Act funding and is currently operating.⁴⁶ 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.⁴⁷

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 is designed to capture 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.⁴⁸ The Petra Nova project reduces CO₂ emissions overall from the entire complex by about 11%. By comparison, in 2016, total U.S. CO₂ emissions from the electricity-generating sector were about 1.8 billion tons.⁴⁹ 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.⁵⁰

Boundary Dam: World's First Addition of CCS to a Large Power Plant

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,⁵¹ cost approximately $1.3 billion according to one source.⁵² 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.⁵³

Similar to the Petra Nova project discussed above, Boundary Dam captures, transports, and sells most of its CO₂ for EOR, shipping 90% of the captured CO₂ via a 41-mile pipeline to the Weyburn Field in Saskatchewan. 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 April 2018, the plant had captured over 2 million tons of CO₂ since full-time operations began in October 2014.⁵⁴ The 115-megawatt (net) plant plans to capture at least 1 million tons of CO₂ per year.⁵⁵

The DOE CCS Program

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 $5 billion total in annual appropriations for CCS activities at DOE. The Recovery Act provided an additional $3.4 billion to that total.⁵⁶

CCS-focused R&D has come to dominate the coal program area within DOE FER&D since 2010. However, the Trump Administration's FY2019 budget request proposes to shift to other priorities, decreasing the overall FER&D budget by nearly $225 million compared to what Congress enacted for FY2018. The FY2019 budget request cites early-stage research as its focus: “This budget request focuses DOE resources toward early-stage R&D and reflects an increased reliance on the private sector to fund later-stage research.” 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 Administration previously proposed cuts to FER&D in its FY2018 budget request; however, Congress increased funding by nearly $59 million (9%) compared to FY2017.

For FY2019, House-passed appropriations legislation would increase overall funding for DOE FER&D by over $58 million compared to the FY2018 amount, and $283 million above the Administration budget request.⁵⁷ The Senate-passed version of the appropriations bill would fund DOE FER&D at about the same level as the FY2018 amount, $727 million, also substantially greater than the Administration's request for $502 million.⁵⁸

Table 2 shows the funding for DOE CCS programs under FER&D from FY2010 through FY2018 and includes the President's FY2019 budget request. Table 2 groups mostly CCS-related programs under the Coal CCS and Power Systems category and the remainder of fossil energy spending under Other Fossil Energy R&D. This grouping follows how Congress has funded these programs. Congress did not accept the Administration's proposed restructuring of the FER&D portfolio in FY2018.

Coal CCS and Power Systems

Compared to the FY2018 total of $727 million enacted for all FER&D, the Administration's FY2019 request of $502 million would be a reduction of approximately 31%. Carbon capture and carbon storage (Table 2) would receive $40 million total under the Administration's request, compared to nearly $200 million for FY2018, an 80% reduction.

The Administration's FY2019 budget request would prioritize the Advanced Energy Systems (AES) account, requesting $175 million, $63 million above the FY2018-enacted amount, nearly a 44% increase. The budget request indicates that AES would focus on six activities: advanced combustion/gasification, advanced turbines, solid oxide fuel cells, advanced sensors and controls, power generation efficiency, and advanced energy materials. Other accounts under the Coal CCS & Power Systems program area are proposed to be funded slightly above or slightly below FY2018 levels, with the exception of CCS activities. Reductions to CCS-related funding would comprise nearly all of the proposed decreased funding for activities in the Coal CCS & Power Systems program area.

Other Fossil Energy Research and Development

The budget request for FY2019 proposes to decrease funding for programs under Other Fossil Energy R&D by nearly $87 million, a 35% reduction compared to FY2018. Program Direction ($60 million in FY2018) provides DOE headquarters support and federal field and contractor support of the FER&D programs overall. Program Direction and National Energy Technology Laboratory (NETL) Coal R&D together provide support to CCS-related activities directly and indirectly.

The budget request proposes to decrease funding for Natural Gas Technologies and Unconventional Fossil activities compared to what Congress enacted in FY2018, from $90 million to $19.5 million for both programs combined. For FY2018, Congress increased funding for those activities (by $16 million compared to FY2017), which support collaborative research to foster development of shale gas resources, the reduction of methane emissions from natural gas infrastructure, and research on gas hydrates. The budget request proposes to eliminate funding for Transformational Coal Pilot programs (called New Fossil Pilot in FY2017). Congress provided $50 million for the program in FY2017 and $35 million in FY2018.⁵⁹

CCS-Related Legislation in the 115^th Congress

A number of bills introduced in the 115^th Congress would potentially affect CCS in the United States. Several bills or provisions of bills address Internal Revenue Code, Section 45Q, providing tax credits for CO₂ capture and sequestration or use as a tertiary injectant for EOR or natural gas production (S. 1535, S. 1663, S. 2256, H.R. 1892, H.R. 2010, H.R. 3761, H.R. 4857, (see Appendix). H.R. 1892, the Bipartisan Budget Act of 2018, was enacted into law as P.L. 115-123. The provisions of P.L. 115-123 that amended Section 45Q and their implications are discussed in more detail in the text box below.

Other bills also would amend the Internal Revenue Code in ways affecting CCS. For example, S. 843 and H.R. 2011 would amend Section 142 of the Internal Revenue Code to allow qualified CO₂ capture facilities that capture 65% or more of their CO₂ emissions to be eligible for tax-exempt private activity bonds.⁶⁰ The bills assert that

allowing tax-exempt financing for the purchase of capital equipment that is used to capture carbon dioxide will reduce the costs of developing carbon dioxide capture projects, accelerate their deployment, and, in conjunction with carbon dioxide utilization and long-term storage, help the United States meet critical environmental, economic, and national security goals.

Several bills would address federal efforts to enhance CCS or emphasize different aspects of the process across three different federal agency and departmental jurisdictions: EPA, DOE, and the Department of Agriculture. S. 2602, for example, would authorize activities under EPA jurisdiction to support direct air capture and utilization of CO₂, and would include carbon capture infrastructure projects as eligible under the FAST Act, as part of the bill's intent to expedite the permitting process for CCS. The legislation would add CCS infrastructure projects explicitly as eligible covered projects, meaning any infrastructure construction activity requiring authorization or environmental review by a federal agency.⁶¹

S. 2803 and H.R. 5745 would amend the Energy Policy Act of 2005 (P.L. 109-58) to authorize DOE to further its CCS research, development, and deployment (RD&D) activities, and place a greater emphasis on CO₂ utilization. S. 2803 would also authorize a project aimed to achieve net-negative CO₂ emissions — projects utilizing biomass and fossil fuels to produce electricity, fuels, or chemicals — with a net removal of CO₂ from the atmosphere. S. 2997 would authorize the Secretary of Agriculture to pursue biomass-related CCS R&D projects, and would authorize the use of loans or loan guarantees for biomass-related CO₂ capture and utilization activities. H.R. 2296 would focus on DOE CCS-related activities and require the department to evaluate its RD&D projects and make recommendations whether each project should continue to receive funding based on progress toward its CCS goals. H.R. 4096 would establish a $5 million prize for CCS-related technology development and commercialization, pursuant to Section 24 of the Stevenson-Wydler Technology Innovation Act of 1980 (15 U.S.C. 3719).⁶² H.R. 5745 would authorize or encourage RD&D activities across the spectrum of CCS, including carbon capture, carbon sequestration, carbon utilization, and carbon removal (including direct air capture), and would authorize a $15 million prize competition to develop direct air capture technology. The bill also would establish a task force to assess the potential for a national system of CO₂ pipelines.

Discussion

Currently the Petra Nova plant in Texas is the sole U.S. commercial large-scale fossil-fueled power plant with CCS, capturing over 1 million tons of CO₂ annually. The Boundary Dam power plant in Canada is the only other commercial fossil-fueled electricity generating plant in the world operating with CCS and capturing a nearly equivalent volume of CO₂. Both plants offset a portion of the cost of CCS by selling CO₂ for the purpose of enhanced oil recovery. Some CCS proponents have hailed the expanded tax credit provision enacted as part of P.L. 115-123, increasing the value of tax credits under Section 45Q of the Internal Revenue Code, as a potential “game changer” for incentivizing more development of large-scale CCS deployment like Petra Nova and Boundary Dam.

Some CCS proponents advocate for other incentives, such as tax-exempt private activity bonds, and enabling eligibility of master limited partnerships for CCS infrastructure projects, which could also increase the financial attractiveness of large-scale capital-intensive CCS endeavors. According to CCS proponents, private activity bonds would allow CCS project developers access to tax-exempt debt, thus lowering their capital costs. Master limited partnerships would allow a corporate structure to combine the tax benefits of a partnership with a corporation's ability to raise capital, reducing the cost of equity and providing access to capital on more favorable terms, according to proponents.

Members of Congress have introduced legislation that would authorize these financial incentives, as well as a suite of other bills aimed at advancing CCS by making CCS infrastructure projects eligible under the FAST Act (42 U.S.C. 4370m(6)), supporting increased research and development for conventional CCS and for carbon utilization technologies and direct air capture of CO₂. Several bills would authorize technology prizes for advances in CCS R&D, including for utilization technologies and direct air capture.

P.L. 115-123 was enacted on February 9, 2018, and it likely will take time to evaluate the impact on U.S. CCS activities. Other factors, such as the price of oil, which could affect demand for EOR and thus CO₂, and the price of natural gas — which could affect the substitution of natural gas for coal in electricity production — will also shape the extent and rapidity of CCS adoption as well. Enactment of other legislation introduced in the 115^th Congress (Appendix) that would provide additional incentives for CCS could also influence future CCS activities.

Ultimately the success of legislative approaches advocated by bill sponsors, and more broadly by CCS proponents, will be measured by how those approaches reduce costs for CCS, through financial incentives, technology development, and commercially viable CO₂-based products, so that the suite of CCS technologies would be more broadly deployed. Absent a policy mandate for reducing CO₂ emissions, or rewarding CO₂ capture and storage or utilization (apart from the 45Q tax incentives enacted in P.L. 115-123), there is broad agreement that costs for CCS would need to decrease before the technologies are commercially deployed across the nation.

The issue of greater CCS deployment is fundamental to the underlying reason CCS is deemed important by a range of proponents: to reduce CO₂ emissions (or reduce the concentration of CO₂ in the atmosphere) and help mitigate against human-induced climate change. The conventional concept of CCS whereby CO₂ emissions from large stationary sources in the United States, such as fossil fuel electricity generating plants, refineries, cement plants, and others was recognized early on as a potential pathway to reducing a large amount greenhouse gas emissions from a relatively small number of point sources.⁶³ The U.S. fossil fuel electricity generation sector alone emitted 1.8 billion tons of CO₂ in 2016, or 34% of total U.S. CO₂ emissions (5.31 billion tons) that year.⁶⁴

The emerging technologies for utilizing CO₂ for a variety of uses and products (carbon utilization, see Figure 5) has energized some CCS advocates because of the commercial potential and prospects for the sequestration of CO₂ in long-lasting products such as cements and plastics. A challenge for utilization advocates is whether the market for carbon utilization products and uses is sufficiently large so that the amount of CO₂ captured or removed from the atmosphere has some measurable effect on human-induced climate change.

Direct air capture (DAC) also has energized some CCS advocates as it offers the promise of net-negative carbon removal if the CO₂ removed by DAC is permanently stored or sequestered. The challenge for DAC is fairly straightforward — how to reduce the cost per ton of CO₂ removed.

Author Contact Information

Peter Folger
Specialist in Energy and Natural Resources Policy
pfolger@crs.loc.gov, 7-1517