Carbon Capture and Sequestration (CCS) in the October 18, 2021
United States
Angela C. Jones
Carbon capture and storage (or sequestration)—known as CCS—is a process that involves
Analyst in Environmental
capturing man-made carbon dioxide (CO2) at its source and storing it permanently underground.
Policy
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
Ashley J. Lawson
of carbon utilization has also gained interest within Congress and in the private sector as a means
Analyst in Energy Policy
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 (CCS is sometimes referred to as CCUS—carbon capture,

utilization, and storage). Direct air capture is a related and emerging technology designed to
remove atmospheric CO2 directly.
The U.S. Department of Energy (DOE) has funded research and development (R&D) in aspects of CCS since at least 1997
within its Fossil Energy and Carbon Management Research, Development, Demonstration, and Deployment program
(FECM) portfolio. Since FY2010, Congress has provided $7.3 billion in appropriations for DOE CCS-related activities,
including annual increases in recent years. In FY2021, Congress provided $750 million to FECM, of which $228.3 million
was directed to CCUS.
Worldwide, according to the Global CCS Institute, 24 facilities capturing and injecting CO2 facilities were operational in
2020, 12 of which are in the United States. U.S. facilities capturing and injecting CO2, and projects under development,
operate in five industry sectors: chemical production, hydrogen production, fertilizer production, natural gas processing, and
power generation. These facilities capture and inject CO2 with the aim to sequester the CO2 in underground geologic
formations or use the CO2 to increase oil production from aging oil fields, known as enhanced oil recovery (EOR). The Petra
Nova project in Texas was the first and only U.S. fossil-fueled power plant generating electricity and capturing CO2 in large
quantities (over 1 million tons per year) until CCS operations were suspended in 2020.
The U.S. Environmental Protection Agency (EPA), under authorities to protect underground sources of drinking water,
regulates CO2 injection through its Underground Injection Control (UIC) program and associated regulations. While the
agency establishes minimum standards and criteria for UIC programs, most states have the responsibility for regulating and
permitting wells injecting CO2 for EOR (classified as Class II recovery wells).
Congress has incentivized development of CCS projects through creation of the Internal Revenue Code Section 45Q tax
credit for carbon sequestration or its use as a tertiary injectant for EOR or other designated purposes. Recent Internal
Revenue Service guidance and regulations on this tax credit are intended to provide increased certainty for industry by
establishing processes and standards for “secure geologic storage of CO2,” among other requirements.
The Consolidated Appropriations Act, 2021 (P.L. 116-260) included several provisions aimed at supporting CCS project
development in the United States. The act revised and expanded DOE’s ongoing CCS research, development, and
demonstration activities, established expedited federal permitting eligibility for CO2 pipelines (where applicable), and
extended the start-of-construction deadline for facilities eligible for the Section 45Q tax credit, among other provisions.
There is broad agreement that costs for CCS would need to decrease before the technologies could be widely deployed across
the nation. In the view of many proponents, greater CCS deployment is fundamental to reduce CO2 emissions (or reduce the
concentration of CO2 in the atmosphere) and to help mitigate human-induced climate change. Congress may also consider
that some stakeholders do not support CCS as a mitigation option, citing concerns with continued fossil fuel combustion and
the uncertainties of long-term underground CO2 storage.
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arbon capture and storage (or sequestration)—known as CCS—is a process that involves
capturing man-made carbon dioxide (CO2) at its source and storing it to avoid its release
C 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) compressing and
transporting the captured CO2 to the storage or 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—in lieu of
storing it—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 and Carbon Management Research, Development, Demonstration,
and Deployment program (FECM).3 From FY2010 to FY2021, Congress provided $7.3 billion in
total appropriations for FECM, much of which was directed to CCS. Additionally, Congress
provided a one-time appropriation of $3.4 billion for CCS in the American Recovery and
Reinvestment Act of 2009 (ARRA; P.L. 111-5). Congress has expressed support for continuing
federal investment in CCS research and development—including financial support for
demonstration projects—through the appropriations process in recent years and in DOE research
reauthorizations provided in the Energy Act of 2020 (Division Z of the Consolidated
Appropriations Act, 2021; P.L. 116-260).
In recent years, Congress has also enacted tax credits for facilities that capture and sequester
CO2—one strategy for incentivizing CCS project deployment. In 2018, Congress enacted
legislation (Title II, §4119 of P.L. 115-123) that increased the tax credit for sequestering or
utilizing CO2, commonly referred to as the “Section 45Q” tax credit.4 In P.L. 116-260, Congress
extended the deadline for start of construction of facilities seeking the tax credit, which, along
with Internal Revenue Service regulations on Section 45Q issued in early 2021, could encourage
more project development, according to some analysts.5
Congressional interest in addressing climate change has also increased interest in CCS, though
debate continues as to what role, if any, CCS should play in deep greenhouse gas reductions.
While some policymakers and other stakeholders support CCS as one option for mitigating CO2
emissions,6 others raise concerns that CCS may not discourage fossil fuel use and that CO2 could

1 Carbon capture and sequestration (CCS) also could be used to capture carbon dioxide (CO2) emissions from power
plants that use bioenergy sources instead of fossil fuels. In that case, the process is known as bioenergy with carbon
capture and storage, or BECCS.
2 See, for example, U.S. Department of Energy (DOE), National Energy Technology Laboratory (NETL), Carbon
Utilization Program, at https://www.netl.doe.gov/coal/carbon-utilization.
3 Formerly called Fossil Energy Research and Development.
4 The credit is codified at 26 U.S.C. §45Q.
5 Carbon Capture Coalition, 45Q Tax Credit, at https://carboncapturecoalition.org/45q-legislation/.
6 For example, the International Energy Agency (IEA) includes CCS as a “key solution” in its 2021 report on achieving
global net zero greenhouse gas emissions. IEA anticipates widespread CCS deployment in several industries (e.g.,
power, cement, and hydrogen production) as well as direct air capture. International Energy Agency (IEA), Net Zero by
2050: A Roadmap for the Global Energy Sector, May 2021.
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leak from underground reservoirs into the air or other reservoirs, thereby negating any climate
benefits of CCS.7
This report includes a primer on the CCS (and carbon utilization) process; overviews of the DOE
program for CCS R&D, U.S. Environmental Protection Agency (EPA) regulation of underground
CO2 injection used for CCS, and the Section 45Q tax credit for CO2 sequestration; and a
discussion of CCS policy issues for Congress. An evaluation of the fate of injected underground
CO2 and the permanence of CO2 storage is beyond the scope of this report.
CCS Primer
An integrated CCS system includes three main steps: (1) capturing and separating CO2 from other
gases; (2) 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 first step, carbon capture. Carbon capture equipment is capital-
intensive to build and energy-intensive to operate. Power plants can supply their own energy to
operate CCS equipment, but the amount of energy a power plant uses to capture and compress
CO2 is that much less electricity the plant can sell to its customers. This difference, sometimes
referred to as the energy penalty or the parasitic load, has been reported to be around 20% of a
power plant’s capacity.8 Figure 1 shows the CCS process schematically from source to storage.

7 For example, see White House Environmental Justice Advisory Council, Climate and Economic Justice Screening
Tool and Justice 40 Interim Final Recommendations, May 13, 2021, p. 58; and Richard Conniff, “Why Green Groups
Are Split on Subsidizing Carbon Capture Technology,” YaleEnvironment360, April 9, 2018.
8 See, for example, Howard J. Herzog, Edward S. Rubin, and Gary T. Rochelle, “Comment on ‘Reassessing the
Efficiency Penalty from Carbon Capture in Coal-Fired Power Plants,’” Environmental Science and Technology, vol. 50
(May 12, 2016), pp. 6112-6113.
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Figure 1. The CCS Process

Source: U.S. Department of Energy, Office of Fossil Energy, “Carbon Utilization and Storage Atlas,” Fourth
Edition, 2012, p. 4.
Notes: EOR is enhanced oil recovery; ECBM is enhanced coal bed methane recovery. Caprock refers to a
relatively impermeable formation. Terms are explained in “CO2 Injection and Sequestration.”
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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 used for enhanced oil
recovery (EOR) in regions of the United States today, and for decades large quantities of fluids
have been injected into the deep subsurface for a variety of purposes, such as disposal of
wastewater from oil and gas operations or of municipal wastewater.9 However, the transport and
storage steps still face challenges, including economic and regulatory issues, rights-of-way,
questions regarding the permanence of CO2 sequestration in deep geological reservoirs, and
ownership and liability issues 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.10 As noted
above, this is typically the most costly part of a CCS project, representing up to 75% of project
costs in some cases.11 Current carbon capture costs are estimated at $43-$65 per ton CO2
captured, though cost reductions of 50%-70% may be possible as the industry matures.12
Currently, three main approaches are available to capture CO2 from large-scale industrial facilities
or power plants: (1) postcombustion capture; (2) precombustion capture; and (3) oxy-fuel
combustion capture.
The following sections summarize each of these approaches. A detailed description and
assessment of the carbon capture technologies is provided in CRS Report R41325, Carbon
Capture: A Technology Assessment, by Peter Folger.
Postcombustion Capture
The process of postcombustion 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.
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.13 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 project (discussed below in “Petra Nova: The First Large U.S. Power
Plant with CCS”), no large U.S. commercial electricity-generating plant has been equipped with
carbon capture equipment, though several projects are under development.

9 Injecting CO2 into an oil reservoir often increases or enhances production by lowering the viscosity of the oil, which
allows it to be pumped more easily from the formation. The process is sometimes referred to as tertiary recovery or
enhanced oil recovery (EOR).
10 Carbon capture is related to, but distinct from, direct air capture (DAC), a process that captures CO2 from the
atmosphere. DAC is discussed in more detail in later sections of this report. For a comparison of CCS and DAC, see
CRS In Focus IF11501, Carbon Capture Versus Direct Air Capture, by Ashley J. Lawson.
11 National Petroleum Council (NPC), Meeting the Dual Challenge: A Roadmap to At-Scale Deployment of Carbon
Capture, Use, and Storage, Chapter 5, July 17, 2020.
12 Greg Kelsall, Carbon Capture Utilisation and Storage - Status, Barriers, and Potential, International Energy Agency
(IEA) Clean Coal Centre, July 2020.
13 Amines are a family of organic solvents, which can “scrub” the CO2 from the flue gas. When the CO2-laden amine is
heated, the CO2 is released to be compressed and stored, and the depleted solvent is recycled.
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Figure 2. Diagram of Postcombustion CO2 Capture in a Coal-Fired Power Plant
Using an Amine Scrubber System
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Source: E. S. Rubin, “CO2 Capture and Transport,” Elements, vol. 4 (2008), pp. 311-317.
Notes: Other major air pol utants (nitrogen oxides-NOx, particulate matter-PM, and sulfur dioxide-SO2) are
removed from the flue gas prior to CO2 capture. PC = pulverized coal. N2 = nitrogen gas.
Precombustion Capture (Gasification)
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 power 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).14 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—known as an integrated gasification combined-cycle
plant (IGCC)—as depicted in Figure 3. Existing IGCC power plants in the United States do not
capture CO2.15
One example of gasification technology in operation today is the Polk Power Station about 40
miles southeast of Tampa, FL.16 The 250 megawatt (MW) unit generates electricity from coal-
derived syngas produced and purified onsite. The Polk Power Station does not capture CO2. An
example of precombustion capture technology, though not for power generation, is 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

14 See CRS Report R41325, Carbon Capture: A Technology Assessment, by Peter Folger.
15 One integrated gasification combined-cycle project in Edwardsport, IN, was designed with sufficient space to add
carbon capture in the future. For further discussion, see DOE, NETL, “IGCC Project Examples,” at https://netl.doe.gov/
research/coal/energy-systems/gasification/gasifipedia/project-examples.
16 For more information about the Polk Power Station, see DOE, NETL, “Tampa Electric Integrated Gasification
Combined-Cycle Project,” at https://netl.doe.gov/research/Coal/energy-systems/gasification/gasifipedia/tampa.
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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.17
Figure 3. Diagram of Precombustion CO2 Capture from an IGCC Power Plant
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Source: E. S. Rubin, “CO2 Capture and Transport,” Elements, vol. 4 (2008), pp. 311-317.
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, thus reducing the formation of smog-forming pollutants like
nitrogen oxides.
Currently oxy-fuel combustion projects are at the lab- or bench-scale, ranging up to verification
testing at a pilot scale.18

17 For a more detailed description of the Great Plains Synfuels plant, see DOE, NETL, “SNG from Coal: Process &
Commercialization,” at https://www.netl.doe.gov/research/coal/energy-systems/gasification/gasifipedia/great-plains.
18 For more information, see NETL, Oxy-Combustion, at https://netl.doe.gov/node/7477.
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Figure 4. Diagram of Oxy-Combustion CO2 Capture from a Coal-Fired Power Plant
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Source: E. S. Rubin, “CO2 Capture and Transport,” Elements, vol. 4 (2008), pp. 311-317.
Allam Cycle
The Allam Cycle is a novel power plant design that uses supercritical CO2 (sCO2) to drive an
electricity-generating turbine.19 sCO2 is CO2 held at certain temperature and pressure conditions,
giving it unique chemical and physical properties. In contrast, most power plants in operation
today (and most proposed power plants using CCS) use steam (i.e., water) to drive a turbine.
Power plants using the Allam Cycle combust fossil fuels in pure oxygen, producing CO2 and
water.20 The CO2 can be reused multiple times to generate electricity, or piped away for utilization
or storage. The excess CO2 produced by the cycle is sufficiently pure to be directly transported or
used without requiring an additional capture or purification step. For power plant operations,
sCO2 may be more efficient than steam. Initial estimates indicate that power plants using the
Allam Cycle could have comparable efficiencies to natural gas combined cycle power plants
without CCS.21
The NET Power demonstration facility in La Porte, TX, is the first power plant to use the Allam
Cycle. Plans for two commercial-scale Allam Cycle power plants—one in Colorado and one in
Illinois—were announced in April 2021.22

19 NET Power, The Allam-Fetvedt Cycle, at https://netpower.com/the-cycle/.
20 The operational NET Power facility uses natural gas as a fuel, but coal may also be used. One of the NET Power
project developers, 8 Rivers Capital, received a DOE grant in 2019 to study the design of a coal-fired power plant using
the Allam Cycle. DOE, “U.S. Department of Energy Invests $7 Million for Projects to Advance Coal Power Generation
Under Coal FIRST Initiative,” at https://netl.doe.gov/node/9282.
21 Rodney Allam et al., “Demonstration of the Allam Cycle: An update on the development status of a high efficiency
supercritical carbon dioxide power process employing full carbon capture,” Energy Procedia, vol. 114 (2017), pp.
5948-5966.
22 Akshat Rathi, “U.S. Startup Plans to Build First Zero-Emission Gas Power Plants,” Bloomberg Green, April 15,
2021.
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CO2 Transport
After the CO2 capture step, the gas is purified and compressed (typically into a supercritical state)
to produce a concentrated stream for transport. Pipelines are the most common method for
transporting CO2 in the United States. Currently, approximately 5,000 miles of pipelines transport
CO2 in the United States, predominantly to oil fields, where it is used for EOR.23 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.
Costs for pipeline construction vary, depending upon length and capacity; right-of-way costs;
whether the pipeline is onshore or offshore; whether the route crosses mountains, large rivers, or
frozen ground; and other factors. The quantity and distance transported will mostly determine
shipping costs. Shipping rates for CO2 pipelines in the United States may be negotiated between
the operator and shippers, or may be subject to rate regulation if they are considered open access
pipelines with eminent domain authority. Siting of CO2 pipelines is under the jurisdiction of the
states, although the federal government regulates their safety.
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 studies have suggested 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, in some cases including federal incentives for CO2 pipeline development.24 In 2020,
enacted legislation included provisions to facilitate the study and development of CO2 pipelines
that could be used for CCS.25
Using marine vessels also may be feasible for transporting CO2 over large distances or overseas.
Liquefied natural gas and liquefied petroleum gases (i.e., propane and butane) are routinely
shipped by marine tankers on a large scale worldwide.26 Marine tankers transport CO2 today, but
at a small scale because of limited demand. Marine tanker costs for CO2 shipping are uncertain,
because no large-scale CO2 transport system via vessel (in millions of tons of CO2 per year, for
example) is operating, although such an operation has been proposed in Europe.27 Marine tanker
shipping might be less costly than pipeline transport for distances greater than 1,000 kilometers
and for less than a few million tons of CO2 transported per year.28

23 Pipeline and Hazardous Materials Safety Administration, “Annual Report Mileage for Hazardous Liquid or Carbon
Dioxide Systems,” web page, July 1, 2020, at https://www.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-
mileage-hazardous-liquid-or-carbon-dioxide-systems.
24 See, for example, Elizabeth Abramson et al., “Transport Infrastructure for Carbon Capture and Storage,” Regional
Carbon Capture Deployment Initiative, June 2020; Ryan W. J. Edwards and Michael A. Celia, “Infrastructure to Enable
Deployment of Carbon Capture, Utilization, and Storage in the United States,” Proceedings of the National Academy of
Sciences, September 18, 2018.
25 USE IT Act (H.R. 1166 and S. 383), 116th Congress, and enacted as part of P.L. 116-260.
26 Rail cars and trucks also can transport CO2, but this mode probably would be uneconomical for large-scale CCS
operations.
27 See IEA Clean Coal Centre, “Northern Lights – Send Us Your CO2,” July 2, 2020. In this report, the amount of CO2
is stated in metric tons, or 1,000 kilograms, which is approximately 2,200 pounds. Hereinafter, the unit tons means
metric tons.
28 Intergovernmental Panel on Climate Change (IPCC) Special Report, Carbon Dioxide Capture and Storage, 2005, p.
31.
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CO2 Injection and Sequestration
Three main types of geological formations are being considered for underground CO2 injection
and sequestration: (1) depleted oil and gas reservoirs, (2) deep saline reservoirs, and (3)
unmineable coal seams. In each case, CO2 in a supercritical state would be injected into a porous
rock formation below ground 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.
The storage capacity for CO2 in geological formations is potentially very large if all the
sedimentary basins in the world are considered.29 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).30 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.31 For CCS to succeed in mitigating atmospheric emissions of CO2, 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.
Table 1. Estimates of the U.S. Storage Capacity for CO2
(in billions of metric tons)

Low
Medium
High
Oil and Natural Gas Reservoirs
186
205
232
Unmineable Coal
54
80
113
Saline Formations
2,379
8,328
21,633
Total
2,618
8,613
21,978
Source: U.S. Department of Energy, National Energy Technology Laboratory, Carbon Storage Atlas, 5th ed.,
August 20, 2015, at https://www.netl.doe.gov/File%20Library/Research/Coal/carbon-storage/atlasv/ATLAS-V-
2015.pdf.

29 Sedimentary basins refer to natural large-scale depressions in the Earth’s surface that are filled with sediments and
fluids and are therefore potential reservoirs for CO2 storage.
30 For comparison, in 2019 the United States emitted 1.6 billion tons of CO2 from the electricity generating sector. See
U.S. Environmental Protection Agency, Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2019, p.
ES-7, at https://www.epa.gov/ghgemissions/draft-inventory-us-greenhouse-gas-emissions-and-sinks-1990-2019.
31 Porosity refers to the amount of open space in a geologic formation—the openings between the individual mineral
grains or rock fragments. Permeability refers to the interconnectedness of the open spaces, or the ability of fluids to
migrate through the formation. Leakage means that the injected CO2 can migrate up and out of the intended reservoir,
instead of staying trapped beneath a layer of relatively impermeable material, such as shale.
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Notes: Data current as of November 2014. The estimates represent only the physical restraints on storage (i.e.,
the pore volume in suitable sedimentary rocks) and do not consider economic or regulatory constraints. The
low, medium, and high estimates correspond to a calculated probability of exceedance of 90%, 50%, and 10%,
respectively, meaning that there is a 90% probability that the estimated storage volume wil exceed the low
estimate and a 10% probability that the estimated storage volume wil exceed the high estimate. Numbers in the
table may not add precisely due to rounding.
Oil and Gas Reservoirs
Pumping CO2 into oil and gas reservoirs to boost production (that is, EOR) has been practiced in
the oil and gas industry for several decades. 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.32 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. The majority of existing
CCS facilities offset some of the costs by selling the captured CO2 for EOR. According to some
studies, EOR using CO2 captured from an industrial source can produce crude oil with a lower
lifecycle greenhouse gas emissions intensity than either oil produced without EOR or oil
produced through EOR using naturally occurring CO2.33 CO2 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.34 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 financial 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.35 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.

32 As of 2014. See Vello Kuuskraa and Matt Wallace, “CO2-EOR Set for Growth as New CO2 Supplies Emerge,” Oil
and Gas Journal, vol. 112, no. 4 (April 7, 2014), p. 66. Hereinafter Kuuskraa and Wallace, 2014.
33 For example, one study comparing lifecycle greenhouse gas emissions of EOR using different sources of CO2 found
that using CO2 captured from an IGCC power plant or a natural gas combined cycle power plant resulted in oil with
25%-60% lower lifecycle greenhouse gas emissions. CO2 source is not the only determinant of the net emissions
reductions associated with EOR. The types of EOR technology and methods also affect estimated emissions reductions
in scientific studies. To a certain extent, EOR can be optimized for CO2 storage (i.e., conducted in such a way as to
attempt to maximize the storage of CO2 as opposed to maximizing the production of oil).
34 As of 2014, nearly two-thirds of oil production using CO2 for EOR came from the Permian Basin, located in western
Texas and southeastern New Mexico. Kruskaa and Wallace, 2014, p. 67.
35 The U.S. Environmental Protection Agency (EPA) regulates this practice under authority of the Safe Drinking Water
Act, Underground Injection Control (UIC) program. See the EPA UIC program at https://www.epa.gov/uic/class-ii-oil-
and-gas-related-injection-wells.
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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.36 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.37 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 offsetting the
cost of CO2 capture. EOR is currently the main use of captured CO2, and some observers envision
EOR will continue to dominate carbon utilization for some time, supporting the scale-up of
capture technologies that could later rely upon other utilization pathways.38 Nonetheless, research
activities and congressional interest in utilization tend to focus on uses other than EOR. For
example, P.L. 115-123, the Bipartisan Budget Act of 2018, which expanded the Section 45Q tax
credit for carbon capture and sequestration, excludes EOR from the definition of carbon
utilization. P.L. 115-123 defines carbon utilization as39
 the fixation of such qualified carbon oxide through photosynthesis or
chemosynthesis, such as through the growing of algae or 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].40
P.L. 116-260 provides two authorizations for a DOE carbon utilization research program (to be
coordinated as a single program) in the aforementioned USE IT Act and Energy Act of 2020.

36 Coal bed and coal seam are interchangeable terms.
37 IPCC Special Report, p. 217.
38 For example, “For good reasons, many seek to find ways to use CO2 to create economic value in a climate-positive
way. Today, the primary use of CO2 is for enhanced oil recovery. This is an important near-term pathway and provides
opportunities to finance projects, scale-up technologies and reduce costs.” Written testimony of Dr. S. Julio Friedmann,
U.S. Congress, Senate Committee on Energy and Natural Resources, Full Committee Hearing to Examine Development
and Deployment of Large-Scale Carbon Dioxide Management Technologies, 116th Cong., 2nd sess., July 28, 2020.
39 CRS In Focus IF11455, The Tax Credit for Carbon Sequestration (Section 45Q), by Angela C. Jones and Molly F.
Sherlock.
40 P.L. 115-123, §41119. A tertiary injectant refers to the use of CO2 for EOR or enhanced natural gas recovery.
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Both focus on “novel uses” for carbon and CO2, such as “chemicals, plastics, building materials,
fuels, cement, products of coal utilization in power systems or in other applications, and other
products with demonstrated market value.”41
Figure 5 illustrates an array of potential utilization pathways: uptake using algae (for biomass
production), conversion to fuels and chemicals, mineralization into inorganic materials, and use
as a working fluid (e.g., for EOR) or other services.
Figure 5. Schematic Illustration of Current and Potential Uses of CO2

Source: U.S. DOE, National Energy Technology Laboratory (NETL), at https://www.netl.doe.gov/coal/carbon-
utilization.
Direct Air Capture
Direct air capture (DAC) is an emerging set of technologies that aim 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”).42
DAC systems typically employ a chemical capture system to separate CO2 from ambient air, add
energy to separate the captured CO2 from the chemical substrate, and remove the purified CO2 to
be stored permanently or utilized for other purposes.43

41 P.L. 116-260, Division S, §102(c).
42 CRS In Focus IF11501, Carbon Capture Versus Direct Air Capture, by Ashley J. Lawson. Some DAC processes
capture CO2 from seawater instead of the atmosphere.
43 For a detailed assessment of DAC technology, see the American Physical Society, Direct Air Capture of CO2 with
Chemicals: A Technology Assessment for the APS Panel on Public Affairs, June 1, 2011, at https://www.aps.org/policy/
reports/assessments/upload/dac2011.pdf. Hereinafter American Physical Society, 2011. Additional background
information is also available in National Academies of Sciences, Engineering, and Medicine, Negative Emissions
Technologies and Reliable Sequestration: A Research Agenda, 2019.
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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 would not necessarily 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.44 A 2011 assessment estimated costs at
roughly $600 per ton of captured CO2.45 A more recent assessment from one of the companies
developing DAC technology, however, projects lower costs for commercially deployed plants of
between $94 and $232 per ton.46 By comparison, some estimate costs for conventional CCS from
coal-fired electricity generating plants in the United States between $48 and $109 per ton.47
Congress has sometimes combined support for CCS and DAC into single proposals, despite the
differences in the technologies. For example, the federal tax credit for carbon sequestration
applies to CCS and DAC projects (with CO2 injection for sequestration).48 In other cases, though,
Congress has treated the technologies separately. For example, the Energy Act of 2020 provided
CCS R&D authorizations primarily in Title IV—Carbon Management, while most DAC R&D
authorizations are in Title V—Carbon Removal.
Commercial CCS Facilities
According to one set of data collected by the Global CCS Institute (GCCSI), 24 commercial CCS
facilities were capturing and injecting CO2 throughout the world in 2020, 12 of which are in the
United States.49 These facilities have a cumulative capacity to capture and store an estimated 40
million tons of CO2 each year.50 Additionally, according to GCCSI, 3 more commercial facilities
were under construction, 34 pilot or demonstration-scale CCS facilities were operational, and 8
CCS technology test centers were operational worldwide, as of 2020.51

44 Generally, the more dilute the concentration of CO2, the higher the cost to extract it, because much larger volumes
are required to be processed. By comparison, the concentration of CO2 in the atmosphere is about 0.04%, whereas the
concentration of CO2 in the flue gas of a typical coal-fired power plant is about 14%.
45 American Physical Society, 2011, p. 13.
46 Robert F. Service, “Cost Plunges for Capturing Carbon Dioxide from the Air,” Science, June 7, 2018, at
http://www.sciencemag.org/news/2018/06/cost-plunges-capturing-carbon-dioxide-air.
47 Lawrence Irlam, The Costs of CCS and Other Low-Carbon Technologies in the United States-2015 Update, Global
CCS Institute, July 2015, p. 1, at http://www.globalccsinstitute.com/publications/costs-ccs-and-other-low-carbon-
technologies-2015-update.
48 For more information, see CRS In Focus IF11455, The Tax Credit for Carbon Sequestration (Section 45Q), by
Angela C. Jones and Molly F. Sherlock.
49 Global CCS Institute, Global Status Report 2020, December 1, 2020. Two facilities, Petra Nova and Lost Cabin,
stopped CCS operations in 2020. The Global CCS Institute defines a commercial facility as a facility capturing CO2 for
permanent storage as part of an ongoing commercial operation, that generally has an economic life similar to the host
facility whose CO2 it captures, and that supports a commercial return while operating and/or meets a regulatory
requirement.
50 Global CCS Institute, Global Status Report 2020, p. 19.
51 Global CCS Institute, Global Status Report 2020, p. 19.
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U.S. CCS facilities in operation or under development occur in five industrial sectors, according
to GCCSI data: chemical production, hydrogen production, fertilizer production, natural gas
processing, and power generation.52 The Archer Daniels Midland (ADM) facility in Decatur, IL,
is the only facility injecting the CO2 solely for geologic sequestration. The facility injects CO2
captured from ethanol production into a saline reservoir and as of 2019 reported that 1.5 million
metric tons of CO2 had been injected at the site.53
Figure 6.Operational and Planned CCS Facilities in the United States Injecting CO2
for Geologic Sequestration and EOR
Global CCS Institute data, as of 2020

Source: CRS, adapted from Global CCS Institute, Global Status Report 2020, 2020.
Notes: Mtpa = mil ion tons per annum (year); circle placement indicates initial year of operations or anticipated
initial year of operations for projects under development, according to GCCSI (the first time frame in the figure
represents 38 years, while the other time frames each represent a five-year period). Some projects under
development anticipate multiple CO2 sources; in these cases, circle placement indicates the initial application
being studied.
Particular attention has been paid to two power generation projects: Boundary Dam, in
Saskatchewan, Canada, and Petra Nova, near Houston, TX. Both projects involved retrofitting
coal-fired electricity generators with carbon capture equipment and have been lauded as
successful examples of carbon capture technology. At the same time, both projects have been
criticized for high costs and for sequestering carbon via EOR. In May 2020, Petra Nova’s owners

52 Global CCS Institute, Global Status Report 2020. “Under development” indicates that some project development.
activity has occurred (e.g., feasibility or design studies), but the facility is not actively capturing and/or injecting CO2.
Projects may be in different stages of development.
53 EPA FLIGHT database, accessed November 16, 2020. For comparison, that facility reported emitting 17.5 million
metric tons of covered GHGs for that same period.
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stopped operating the CCS equipment, citing unfavorable economics due to low crude oil prices,
though reports suggest the facility may have experienced prior mechanical challenges.54
Petra Nova: The First Large U.S. Power Plant with CCS
On January 10, 2017, the Petra Nova–W.A. Parish Generating Station became the first industrial-
scale coal-fired power plant with CCS to operate in the United States. The plant began capturing
approximately 5,000 tons of CO2 per day from its 240-megawatt-equivalent slipstream using post
combustion capture technology.55 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 designed to capture 1.4 million tons of CO2 each year.56 The captured CO2 is transported
via an 82-mile pipeline to the West Ranch oil field, where it is injected for 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),
anticipated increasing West Ranch oil production from 300 barrels per day before EOR to 15,000
barrels per day after EOR.57 Petra Nova’s operators turned off the CCS equipment in May 2020,
citing low oil prices caused, in part, by the COVID-19 pandemic.58
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 (ARRA; P.L. 111-5) together with other DOE funding for a total of
more than $190 million of federal funds for the $1 billion retrofit project.59 Petra Nova is the only
CCPI Round 3 project that expended its ARRA funding and began operating.60 The three other
CCPI Round 3 demonstration projects funded using ARRA appropriations (as well as the
FutureGen project—slated to receive nearly $1 billion in ARRA appropriations) all have been
canceled, have been suspended, or remain in development.61

54 Jeremy Dillon and Carlos Anchondo, “Low Oil Prices Force Petra Nova Into ‘Mothball Status,’” E&E News, July 28,
2020; and Nichola Groom, “Problems Plagued U.S. CO2 Capture Project Before Shutdown: DOE Document,” Reuters,
August 6, 2020.
55 Slipstream refers to the exhaust gases emitted from the power plant. NRG News Release, “NRG Energy, JX Nippon
Complete World’s Largest Post-Combustion Carbon Capture Facility On-Budget and On-Schedule,” January 10, 2017,
at http://investors.nrg.com/phoenix.zhtml?c=121544&p=irol-newsArticle&ID=2236424.
56 U.S. Department of Energy (DOE), National Energy Technology Laboratory (NETL), “Recovery Act: Petra Nova
Parish Holdings: W.A. Parish Post-Combustion CO2 Capture and Sequestration Project,” at https://www.netl.doe.gov/
research/coal/project-information/fe0003311.
57 NRG News Release, “NRG Energy, JX Nippon Complete World’s Largest Post-Combustion Carbon Capture Facility
On-Budget and On-Schedule,” January 10, 2017, at http://investors.nrg.com/phoenix.zhtml?c=121544&p=irol-
newsArticle&ID=2236424.
58 L.M.Sixel, “NRG Mothballs Carbon Capture Project at Coal Plant,” Houston Chronicle, July 31, 2020.
59 U.S. Department of Energy (DOE), National Energy Technology Laboratory (NETL), “Recovery Act: Petra Nova
Parish Holdings: W.A. Parish Post-Combustion CO2 Capture and Sequestration Project,” at https://www.netl.doe.gov/
research/coal/project-information/fe0003311.
60 For an analysis of carbon capture and sequestration (CCS) projects funded by the American Recovery and
Reinvestment Act (P.L. 111-5), see CRS Report R44387, Recovery Act Funding for DOE Carbon Capture and
Sequestration (CCS) Projects, by Peter Folger.
61 FutureGen is discussed in more detail in CRS Report R44387, Recovery Act Funding for DOE Carbon Capture and
Sequestration (CCS) Projects, by Peter Folger.
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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,62 cost
approximately $1.3 billion, according to one source.63 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.64
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 June 2020, the plant had captured over 3.4 million tons of CO2
since full-time operations began in October 2014.65
The DOE CCS Program
DOE has funded R&D of aspects of the three main steps of an integrated CCS system since 1997,
primarily through its Fossil Energy and Carbon Management Research, Development,
Demonstration, and Deployment program (FECM).66 CCS-focused R&D has come to dominate
the coal program area within DOE FECM since 2010. Since FY2010, Congress has provided $7.3
billion total in annual appropriations for FECM (see Table 2). ARRA provided an additional $3.4
billion to that total, specifically for CCS projects.67
The Trump Administration proposed shifting FECM’s focus to early-stage research, as
summarized in the FY2021 budget request for FECM: “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, development, and commercialization of energy technologies.”68 The Trump
Administration’s approach would have been a reversal of Obama Administration and George W.

62 SaskPower is the principal electric utility in Saskatchewan, Canada.
63 MIT Carbon Capture & Sequestration Technologies, CCS Project Database, “Boundary Dam Fact Sheet: Carbon
Capture and Storage Project,” at http://sequestration.mit.edu/tools/projects/boundary_dam.html.
64 Ibid.
65 SaskPower, BD3 Status Update: June 2020, at https://www.saskpower.com/about-us/our-company/blog/bd3-status-
update-june-2020.
66 The Fossil Energy and Carbon Management Research, Development, Demonstration, and Deployment
appropriations account was previously known as the Fossil Energy Research and Development (FER&D) account. The
Biden Administration renamed the Office of Fossil Energy as the Office of Fossil Energy and Carbon Management in
2021. This name change was also adopted by appropriators throughout the FY2022 appropriations process. See DOE,
“Our New Name Is Also a New Vision,” July 8, 2021, at https://www.energy.gov/fe/articles/our-new-name-also-new-
vision.
67 Authority to expend American Recovery and Reinvestment Act (ARRA; P.L. 111-5) funds expired in 2015. An
analysis of ARRA funding for CCS activities at DOE is provided in CRS Report R44387, Recovery Act Funding for
DOE Carbon Capture and Sequestration (CCS) Projects, by Peter Folger.
68 DOE, FY2021 Congressional Budget Request, Volume 3 Part 2, February 2021, p. 195.
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Bush Administration DOE policies, which supported large carbon-capture demonstration projects
and large injection and sequestration demonstration projects. Congress instead provided annual
increases in the first three years of the Trump Administration and continued support for
demonstration projects. The Biden Administration has also supported funding CCS demonstration
projects. Table 2 shows the funding for DOE CCS programs under FECM from FY2010 through
FY2021.69

69 For information on FY2021 and FY2022 appropriations, see CRS In Focus IF11861, Funding for Carbon Capture
and Carbon Removal at DOE, by Ashley J. Lawson.
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Table 2. Funding for DOE Fossil Energy and Carbon Management Research, Development, Demonstration, and Deployment
Program (FECM) Program Areas
FY2010 through FY2021
FECM Program
Program/
FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 FY2016
FY2017
FY2018
FY2019
FY2020
FY2021
Areas
Activity
($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000)
CCUS and Power
Carbon Capture
—
58,703
66,986
63,725
92,000
88,000
101,000
101,000
100,671
100,671
117,800
126,300
Systems

Carbon

23,000
Utilization

Carbon Storage
—
120,912
112,208
106,745
108,766
100,000
106,000
95,300
98,096
98,096
100,000
79,000

Advanced Energy
—
168,627
97,169
92,438
99,500
103,000
105,000
105,000
112,000
129,683
120,000
122,000
Systems

Cross-Cutting
—
41,446
47,946
45,618
41,925
49,000
50,000
45,500
58,350
56,350
56,000
72,000
Research

Supercritical
—
—
—
—
—
10,000
15,000
24,000
24,000
22,430
16,000
14,500
CO2 Technology

NETL Coal R&D
—
—
35,011
33,338
50,011
50,000
53,000
53,000
53,000
54,000
61,000
0

Transformational
—
—
—
—
—
—
—
50,000a
35,000
25,000
20,000
10,000
Coal Pilotsa
Subtotal CCUS and
393,485 389,688 359,320 341,864 392,202 400,000 430,000
423,800
481,117
486,230
490,800
446,800
Power Systems
Other FECM
Natural Gas
17,364
0
14,575
13,865
20,600
25,121
43,000
43,000
50,000
51,000
51,000
57,000
Technologies

Unconventional
19,474
0
4,859
4,621
15,000
4,500
20,321
21,000
40,000
46,000
46,000
46,000
Fossil

Program
158,000
164,725
119,929
114,201
120,000
119,000
114,202
60,000
60,000
61,070
61,500
61,500
Direction

Plant and Capital
20,000
19,960
16,794
15,982
16,032
15,782
15,782
—
—
—
—
—
CRS-18

FECM Program
Program/
FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 FY2016
FY2017
FY2018
FY2019
FY2020
FY2021
Areas
Activity
($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000) ($1,000)

Env. Restoration
10,000
9,980
7,897
7,515
5,897
5,897
7,995
—
—
—
—
—

Special
700
699
700
667
700
700
700
700
700
700
700
700
Recruitment

NETL Research
—
—
—
—
—
—
0
43,000
50,000
50,000
50,000
83,000
and Operations

NETL
—
—
—
—
—
—
0
40,500
45,000
45,000
50,000
55,000
Infrastructure

Coop R&D
4,868
—
—
—
—
—
—
—
—
—

Directed
35,879
—
—
—
—
—
—
—
—
—

Projects
Subtotal Other

266,285 195,364 164,754 156,851 178,229 171,000 202,000
258,200
245,700
253,770
259,200
303,200
FECM
Rescissions/Use of

— (151,000) (187,000)
—
—
—
—
(14,000)
—
—

Prior-Year Balances
Total FECM

659,770 434,052 337,074 498,715 570,431 571,000 632,000
668,000
726,817
740,000
750,000
750,000
FY2010-FY2021
Grand Total
$7.3B

Sources: U.S. Department of Energy annual budget justifications for FY2012 through FY2021; explanatory statement for P.L. 115-141, Division D (Consolidated
Appropriations Act, 2018, at https://rules.house.gov/bil /115/hr-1625-sa).
Notes: CO2 = carbon dioxide; CCUS = carbon capture utilization and sequestration (or storage); FECM = Fossil Energy and Carbon Management Research,
Development, Demonstration, and Deployment program; NETL = National Energy Technology Laboratory; Inf. & Ops = infrastructure and operations; Coop =
cooperative; R&D = research and development. Directed Projects refer to congressionally directed projects. Program areas are as used in the explanatory statement for
FY2021 appropriations; previous appropriations language used alternative names for some program areas and may not be completely comparable. Grand total for
FY2010-FY2021 subject to rounding. Amounts provided by the American Recovery and Reinvestment Act of 2009 (ARRA; P.L. 111-5) are not shown in the table or
included in the grand total. The carbon utilization program was first authorized for FY2021 as part of P.L. 116-260.
a. Funding for Transformational Coal Pilots was first provided as a proviso in FY2017 appropriations. See explanatory statement for P.L. 115-31, Consolidated
Appropriations Act, 2017, Division D at https://www.gpo.gov/fdsys/pkg/CPRT-115HPRT25289/pdf/CPRT-115HPRT25289.pdf.

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Carbon Capture and Sequestration (CCS) in the United States

EPA Regulation of Underground Injection in CCS
EPA issues regulations for underground injection of CO2 as part of its responsibilities for
underground injection control (UIC) programs under the Safe Drinking Water Act (SDWA). EPA
also develops guidance to support state program implementation, and in some cases, directly
administers UIC programs in states.70 The agency has established minimum requirements for state
UIC programs and permitting for injection wells. These requirements include performance
standards for well construction, operation and maintenance, monitoring and testing, reporting and
recordkeeping, site closure, financial responsibility, and, for some types of wells, post injection
site care. Most states implement the day-to-day program elements for most categories of wells,
which are grouped into “classes” based on the type of fluid injected. Owners or operators of
underground injection wells must follow the permitting requirements and standards established
by the UIC program authority in their state.
EPA has issued regulations for six classes of underground injection wells based on type and depth
of fluids injected and potential for endangerment of underground sources of drinking water
(USDWs). Class II wells are used to inject fluids related to oil and gas production, including
injection of CO2 for EOR. Class VI wells are used to inject CO2 for geologic sequestration. There
are more than 119,500 EOR wells injecting CO2 in the United States, predominantly in
California, Texas, Kansas, Illinois, and Oklahoma.71 This includes EOR wells used to inject CO2
captured from anthropogenic sources and wells using naturally derived CO2. Two EPA-permitted
wells are currently operating for sequestration in the United States, both located at the ADM
facility in Illinois.72
To protect USDWs from injected CO2 or movement of other fluids in an underground formation,
Class II EOR wells must transition to Class VI geologic sequestration wells under certain
conditions.73 Class II well owners or operators who inject CO2 primarily for long-term storage
(rather than oil production) must obtain a Class VI permit when there is an increased risk to
USDWs compared to prior Class II operations using CO2. The Class VI Program Director (EPA
or a delegated state) determines whether a Class VI permit is required based on site-specific risk
factors associated with USDW endangerment. To date, no such transition has been required.

70 40 C.F.R. §§144-147.
71 EPA, FY19 State UIC Injection Well Inventory, accessed November 27, 2020.
72 EPA has granted North Dakota and Wyoming primary enforcement authority for Class VI well programs in those
states.
73 40 C.F.R. §144.19.
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The 45Q Tax Credit for CCS74
Title II, Section 41119 of P.L. 115-123, the Bipartisan Budget Act of 2018, amended Internal Revenue Code Section
45Q to increase the tax credit for capture and sequestration of “carbon oxide,” or for its use as a tertiary
injectant in EOR operations. Carbon oxide is defined variously in the legislation to include CO2, or any other
carbon oxide—such as carbon monoxide—that qualifies under provisions of the enacted law. The law raises the
tax credit linearly from $22.66 to $50 per ton over the period from calendar year 2017 until calendar year 2026
for CO2 captured and permanently stored, and from $12.83 to $35 per ton over the same period for CO2
captured and used as a tertiary injectant. Starting with calendar year 2027, the tax credit wil be adjusted for
inflation. It also requires that the credit be claimed over a 12-year period after operations begin. Additionally, to
qualify, facilities must begin construction before January 1, 2026.75
To qualify, a minimum amount of CO2 is required to be captured and stored or utilized by the facility.76 This
amount varies with the type of facility. An electricity generating facility that emits more than 500,000 tons of CO2
per year, for example, must capture a minimum 500,000 tons of CO2 annually to qualify for the tax credit. A
facility that captures CO2 for the purposes of utilization—fixing CO2 through photosynthesis or chemosynthesis,
converting it to a material or compound, or using it for any commercial purpose other than tertiary injection or
natural gas recovery (as determined by the Secretary of the Treasury)—and emits less than 500,000 tons of CO2
must capture at least 25,000 tons per year. A direct air capture facility or a facility that does not meet the other
criteria just described must capture at least 100,000 tons per year.
The modifications to 45Q in P.L. 115-123 also changed taxpayer eligibility for claiming the credit. For equipment
placed in service before February 9, 2018, the credit is attributable to the person that captures and physically or
contractually ensures the disposal or use of qualified CO2, unless an election is made to allow the person disposing
of the captured CO2 to claim the credit. For equipment placed in service after February 9, 2018, the credit is
attributable to the person that owns the carbon capture equipment and physically or contractually ensures the
disposal or use of the qualified CO2. The credits can be transferred to the person that disposes of or uses the
qualified CO2. Proponents of this change suggest it provides greater flexibility for companies with different
business models to use the tax credit effectively, including cooperative and municipal utilities.
Some stakeholders have suggested that the 2018 tax credit increases in Section 45Q could be a “game changer”
for CCS developments in the United States, by providing high-enough incentives for investments into CO2 capture
and storage.77 They note that EOR has been the main driver for CCS development until now, and the new tax
credit incentives might result in an increased shift toward CO2 capture for permanent storage apart from EOR.
Opponents to 45Q include some environmental groups that broadly oppose measures that extend the life of coal-
fired power plants or provide incentives to private companies to increase oil production.78 Another factor to
consider is the cost. According to the Joint Committee on Taxation (JCT), the changes enacted in P.L. 115-123
wil reduce federal tax revenue by an estimated $689 mil ion between FY2018 and FY2027.79 Other groups note
that measures in addition to the 45Q tax credits wil be needed to lower CCS costs and promote broader
deployment.
The Internal Revenue Service (IRS) continues to issue guidance and promulgate regulations on implementation of
the Section 45Q tax credit. In January 2021, the IRS issued final regulations on demonstration of “secure geologic
storage,” utilization of qualified carbon oxide, eligibility, and credit recapture, among other provisions (86 Federal
Register, January 15, 2021, 4728-4773).
Discussion
In recent Congresses, proposed and enacted CCS-related legislation has addressed federal CCS
RD&D activities and funding, CO2 pipelines, and the carbon sequestration tax credit. More than

74 For additional background, see CRS InFocus IF11455, The Tax Credit for Carbon Sequestration (Section 45Q), by
Angela C. Jones and Molly F. Sherlock.
75 The begin-construction deadline was extended from January 1, 2024, to January 1, 2026, in the Taxpayer Certainty
and Disaster Tax Relief Act of 2020 (Division EE of the Consolidated Appropriations Act, 2021; P.L. 116-260).
76 Taxpayers must physically or contractually dispose of captured carbon oxide in secure geological storage. See IRS
Prop. Reg. §1.45Q-1, Prop. Reg. §1.45Q-2, Prop. Reg. §1.45Q-3, Prop. Reg. §1.45Q-4, and Prop. Reg. §1.45Q-5; and
Department of the Treasury, “Credit for Carbon Oxide Sequestration,” 85 Federal Register 34050-34075, June 2, 2020.
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55 bills were introduced in the 116th Congress that contained provisions addressing CCS. Some of
these bills, or provisions thereof, were enacted as part of the Consolidated Appropriations Act,
2021 (P.L. 116-260). Potential implementation and oversight issues related to these provisions
might be of interest in the 117th Congress. In 2021, the Biden Administration has announced
climate change mitigation goals and strategies, and new climate-focused groups and initiatives
that may also be of interest when considering CCS-related oversight, appropriations, or
legislation.
In the 116th Congress, as part of the Consolidated Appropriations Act, 2021 (P.L. 116-260),
Congress reauthorized the DOE CCS research program. Among other provisions, the law
expanded the scope of DOE’s research to noncoal applications (e.g., natural gas-fired power
plants, other industrial facilities).80 The law also authorized a DOE carbon utilization research
program and specific activities related to direct air capture (e.g., a DAC technology prize). As is
also true for other DOE applied research programs, some criticize such activities as an
inappropriate role for government, arguing the private sector is better suited to develop
technologies that can compete in the marketplace.
Costs have been, and remain, a key challenge to CCS development in the United States. In recent
years, Congress has attempted to address this challenge in two main ways—federal R&D and
federal tax credits. P.L. 116-260 also extended the start of construction deadline for facilities
claiming the 45Q tax credit. The tax credit is considered by some stakeholders as one of the
strongest policies supporting CCS in the world.81 In January 2021, the IRS promulgated
regulations establishing requirements for carbon storage under Section 45Q. Congress remains
interested in the efficacy of the tax credit in promoting CCS development and could consider
additional adjustments to it.
The issue of expanded CCS deployment is closely tied to the issue of reducing greenhouse gas
emissions to mitigate human-induced climate change. In two January 2021 executive orders,
President Biden outlined new federal climate policies; created new White House and Department
of Justice climate offices; and established new task forces, workgroups, and advisory committees
on climate change science and policy.82 At this early stage, the implications of these executive
branch policies and actions on CCS project development and deployments are unclear.

77 Emma Foehringer Merchant, “Can Updated Tax Credits Bring Carbon Capture Into the Mainstream?,” Greentech
Media, February 22, 2018; James Temple, “The Carbon Capture Era May Finally Be Starting,” MIT Technology
Review, February 20, 2018.
78 “Capturing Carbon Pollution While Moving Beyond Fossil Fuels,” Natural Resources Defense Council, assessed on
November 27, 2019, at https://www.nrdc.org/experts/david-doniger/capturing-carbon-pollution-while-moving-beyond-
fossil-fuels; Richard Conniff, “Why Green Groups are Split on Subsidizing Carbon Capture Technology,”
YaleEnvironment360, April 9, 2018.
79 Joint Committee on Taxation, Estimated Effects of the Revenue Provisions Contained in the “Bipartisan Budget Act
of 2018,” JCS-4-18, February 8, 2018.
80 For additional information, see CRS In Focus IF11861, Funding for Carbon Capture and Carbon Removal at DOE,
by Ashley J. Lawson.
81 For example, “45Q: The most progressive CCS-specific incentive globally,” Lee Beck, The U.S. Section 45Q Tax
Credit for Carbon Oxide Sequestration: An Update, Global CCS Institute, p. 2, April 2020.
82 Executive Order 13990, Protecting Public Health and the Environment and Restoring Science to Tackle the Climate
Crisis, January 20, 2021; and Executive Order 14008, Tackling the Climate Crisis at Home and Abroad, January 27,
2021.
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An additional consideration in the congressional policy discussion is that not all advocates for
actions to address climate change support CCS technology.83 Some argue that CCS supports
continued reliance on fossil fuels, which runs counter to reducing greenhouse gas emissions and
other environmental goals. They tend to prefer policies that phase out the use of fossil fuels
altogether. Other CCS opponents raise concerns about the long-term safety and environmental
uncertainties of injecting large volumes of CO2 underground.

Author Information

Angela C. Jones
Ashley J. Lawson
Analyst in Environmental Policy
Analyst in Energy Policy

Acknowledgments
CRS Specialist Paul Parfomak provided substantial contributions to the CO2 Transport Section of this
report. CRS Specialist Peter Folger authored the original version of this report. CRS Intern Claire Mills
contributed research related to lifecycle greenhouse gas emissions for different enhanced oil recovery
processes.

Disclaimer
This document was prepared by the Congressional Research Service (CRS). CRS serves as nonpartisan
shared staff to congressional committees and Members of Congress. It operates solely at the behest of and
under the direction of Congress. Information in a CRS Report should not be relied upon for purposes other
than public understanding of information that has been provided by CRS to Members of Congress in
connection with CRS’s institutional role. CRS Reports, as a work of the United States Government, are not
subject to copyright protection in the United States. Any CRS Report may be reproduced and distributed in
its entirety without permission from CRS. However, as a CRS Report may include copyrighted images or
material from a third party, you may need to obtain the permission of the copyright holder if you wish to
copy or otherwise use copyrighted material.

83 For example, in its May 2021 interim final recommendations, the White House Environmental Justice Advisory
Council (WHEJAC) listed CCS projects as among those projects that would not benefit communities (WHEJAC,
Justice40, Climate and Economic Justice Screening Tool & Executive Order 12898 Revisions: Interim Final
Recommendations, May 13, 2021). See also Carlos Anchondo, “Industry warns lawmakers of CCS threats,”
Energywire, November 25, 2019; and Richard Conniff, “Why Green Groups Are Split on Subsidizing Carbon Capture
Technology,” YaleEnvironment360, April 9, 2018.
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