Carbon Capture and Sequestration (CCS) in the United States

Carbon Capture and Sequestration (CCS) in the United States

Carbon Capture and Sequestration (CCS) in the October 5, 2022
United States
Angela C. Jones
Carbon capture and storage (or sequestration)—known as CCS—is a process intended to capture
Analyst in Environmental
man-made carbon dioxide (CO2) at its source and store it permanently underground. As one
Policy
potential option for greenhouse gas mitigation, CCS could reduce the amount of CO2—an

important greenhouse gas—emitted to the atmosphere from power plants and other large
Ashley J. Lawson
industrial facilities. The concept of carbon utilization has also gained interest within Congress
Analyst in Energy Policy
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. CCS is sometimes

referred to as CCUS—carbon capture, utilization, and storage. Direct air capture (DAC) 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 a total of $9.2 billion (in constant 2022 dollars) in annual
appropriations for FECM, of which $2.7 billion (in constant 2022 dollars) was directed to CCS-related budget line items. The
Infrastructure Investment and Jobs Act (IIJA; P.L. 117-58) provided $8.5 billion (nominal dollars) in supplemental funding
for CCS for FY2022-FY2026, including funding for the construction of new carbon capture facilities, plus another $3.6
billion (nominal dollars) for DAC.
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. Most projects use the
injected CO2 to increase oil production from aging oil fields, known as enhanced oil recovery (EOR), while some facilities
capture and inject CO2 with the aim to sequester the CO2 in underground geologic formations. The Petra Nova project in
Texas, starting operation in 2017, was the first and only U.S. fossil-fueled power plant generating electricity and capturing
CO2 in large quantities (over 1 million metric 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, 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.
Several provisions in the Consolidated Appropriations Act, 2021 (P.L. 116-260) aim to further support 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. IIJA
included additional supportive provisions. P.L. 117-169, commonly known as the Inflation Reduction Act of 2022, contained
several provisions related to the 45Q tax credit that increase the amount of the tax credit for certain facilities and extend the
deadline for start of construction, among other provisions.
There is broad agreement that costs for constructing and operating CCS would need to decrease before the technologies could
be widely deployed. In the view of many proponents, greater CCS deployment is fundamental to reduce CO2 emissions (or
reduce the concentration of CO2 in the atmosphere, in the case of DAC) and to help mitigate human-induced climate change.
In contrast, 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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Contents
CCS Primer...................................................................................................................................... 2
CO2 Capture ............................................................................................................................... 4
Postcombustion Capture ..................................................................................................... 4
Precombustion Capture (Gasification) ................................................................................ 5
Oxy-Fuel Combustion Capture ........................................................................................... 6
Allam Cycle ........................................................................................................................ 7
CO2 Transport ............................................................................................................................ 8
CO2 Injection and Sequestration ............................................................................................... 9
Oil and Gas Reservoirs ..................................................................................................... 10
Deep Saline Reservoirs ..................................................................................................... 10
Unmineable Coal Seams .................................................................................................... 11
Carbon Utilization .................................................................................................................... 11
Commercial CCS Facilities ........................................................................................................... 14
Petra Nova: The First Large U.S. Power Plant with CCS ....................................................... 17
Boundary Dam: World’s First Addition of CCS to a Large Power Plant ................................ 18
The DOE CCS Program ................................................................................................................ 18
EPA Regulation of Underground Injection in CCS ....................................................................... 23
Discussion ..................................................................................................................................... 26
Council on Environmental Quality 2021 CCS Report to Congress and 2022 CCS
Guidance .............................................................................................................................. 26
Other CCS Policy Issues ......................................................................................................... 27

Figures
Figure 1. Options for an Integrated CCS Process: Capture, Injection, and Utilization ................... 3
Figure 2. Diagram of Postcombustion CO2 Capture in a Coal-Fired Power Plant Using an
Amine Scrubber System ............................................................................................................... 5
Figure 3. Diagram of Precombustion CO2 Capture from an IGCC Power Plant............................. 6
Figure 4. Diagram of Oxy-Combustion CO2 Capture from a Coal-Fired Power Plant ................... 7
Figure 5. Schematic Illustration of Current and Potential Uses of CO2 ........................................ 12
Figure 6. Location of U.S. Carbon Capture and Injection Projects ............................................... 14
Figure 7. Operational, Planned, and Suspended Facilities in the United States Injecting
CO2 for Geologic Sequestration and EOR ................................................................................. 16

Tables
Table 1. Estimates of the U.S. Storage Capacity for CO2 ................................................................ 9
Table 2. Annual Appropriations for DOE Fossil Energy and Carbon Management
(FECM) Research, Development, Demonstration, and Deployment Program Areas ................ 19
Table 3. Infrastructure Investment and Jobs Act Supplemental Appropriations for Carbon
Capture and Storage Programs ................................................................................................... 22

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Contacts
Author Information ........................................................................................................................ 28

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arbon capture and storage (or sequestration)—known as CCS—is a process intended to
capture man-made carbon dioxide (CO2) at its source and store it to avoid its release to the
C 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 power plants and
other large industrial facilities. An integrated CCS system would include three main steps: (1)
capturing and separating CO2 from other gases; (2) transporting the captured and compressed 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”). The utilization part of CCUS has
been of increased interest to researchers and policymakers. 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.1 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, currently within its Fossil Energy and Carbon Management Research, Development,
Demonstration, and Deployment program (FECM).2 From FY2010 to FY2022, Congress
provided a total of $9.2 billion (2022 dollars)3 in annual appropriations for FECM, of which $2.7
billion (2022 dollars) was directed to CCS-related budget line items. Additionally, Congress
provided a supplemental appropriation of $3.4 billion ($4.4 billion in 2022 dollars) for CCS in the
American Recovery and Reinvestment Act of 2009 (ARRA; P.L. 111-5). It provided another
supplemental appropriation of $8.5 billion (nominal dollars) for CCS in the Infrastructure
Investment and Jobs Act (IIJA; P.L. 117-58) for FY2022 to FY2026.4 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). The IIJA provided funding for several
programs authorized by the Energy Act of 2020 and established other programs aimed to promote
CCS in the United States, as discussed later in this report.
Congress has also enacted tax credits for facilities that capture and sequester CO2—one strategy
for incentivizing CCS project deployment. In 2022, Congress enacted as part of P.L. 117-260,
commonly known as the Inflation Reduction Act of 2022 (IRA), provisions that increased the tax
credit for sequestering or utilizing CO2, referred to as the “Section 45Q” tax credit.5 The IRA also
extended the deadline for start of construction of certain facilities seeking the tax credit. The
Internal Revenue Service regulations on Section 45Q issued in early 2021 could provide a more
stable investment environment for project planning.
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 greenhouse gas emissions reductions.
While some policymakers and other stakeholders support CCS as one option for mitigating CO2
emissions, others raise concerns that CCS may encourage continued fossil fuel use and that CO2

1 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.
2 Formerly called Fossil Energy Research and Development.
3 Throughout this report, nominal dollars are converted to Q2 2022 dollars (referred to in this report as 2022 dollars)
using the price index for federal government investment in research and development from Bureau of Economic
Analysis, “National Income and Product Accounts,” Table 3.9.4.
4 For more information, see CRS Report R47034, Energy and Minerals Provisions in the Infrastructure Investment and
Jobs Act (P.L. 117-58), coordinated by Brent D. Yacobucci.
5 The credit is codified at 26 U.S.C. §45Q.
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could leak from underground reservoirs into the air or other reservoirs, thereby negating climate
benefits of CCS.6
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.7 Figure 1 shows the options for parts of an integrated CCS process
schematically from source to storage.

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. See also the 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.
7 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. Options for an Integrated CCS Process: Capture, Injection, and Utilization

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.8 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.9 As noted
above, this is typically the most costly part of a CCS project, representing up to 75% of project
costs in some cases.10 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.11
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.12 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 2017-2020 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.

8 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). EOR may involve incidental carbon storage.
9 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.
10 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.
11 Greg Kelsall, Carbon Capture Utilisation and Storage - Status, Barriers, and Potential, International Energy Agency
(IEA) Clean Coal Centre, July 2020.
12 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).13 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. This 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 CO2.14
One example of IGCC technology in operation today is the Polk Power Station about 40 miles
southeast of Tampa, FL.15 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

13 See CRS Report R41325, Carbon Capture: A Technology Assessment, by Peter Folger.
14 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.
15 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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lignite coal through a gasification process, and the natural gas is shipped out of the facility for
sale in the natural gas market. The process also produces a stream of high-purity CO2, which is
piped northward into Canada for use in EOR at the Weyburn oil field.16
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.17

16 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.
17 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.18 sCO2 is CO2 held at certain temperature and pressure conditions,
giving it unique chemical and physical properties.19 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

18 NET Power, The Allam-Fetvedt Cycle, at https://netpower.com/the-cycle/.
19 Supercritical CO2 refers to temperature and pressure conditions above a critical point where CO2 has characteristics
of both a gas and a liquid. In this “supercritical” state, small changes in temperature or pressure can result in large
changes in density, which can make supercritical CO2 a useful working fluid for power generation. The critical point
for CO2 refers to the temperature and pressure conditions above which matter phase boundaries disappear.
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.
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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
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. 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.24
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 emissions reduction using CCS may require a
concerted federal policy, in some cases including federal incentives for CO2 pipeline
development.25 In 2020, enacted legislation included provisions to facilitate the study and
development of CO2 pipelines that could be used for CCS.26
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.27 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 metric tons of CO2 per
year, for example) is operating, although such an operation has been proposed in Europe.28

22 Akshat Rathi, “U.S. Startup Plans to Build First Zero-Emission Gas Power Plants,” Bloomberg Green, April 15,
2021.
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 For additional information on CO2 pipeline safety, see CRS Insight IN11944, Carbon Dioxide Pipelines: Safety
Issues, by Paul W. Parfomak.
25 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.
26 USE IT Act (H.R. 1166 and S. 383), 116th Congress, and enacted as part of P.L. 116-260.
27 Rail cars and trucks also can transport CO2, but this mode probably would be uneconomical for large-scale CCS
operations.
28 See IEA, “Northern Lights.”
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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 when considering all the sedimentary basins in the world is
potentially very large compared to total CO2 emissions from stationary sources.29 In the United
States alone, DOE has estimated the total storage capacity to range between about 2.6 trillion and
22 trillion metric 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 the electricity generating sector and other 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 2020 the United States emitted 1.4 billion metric tons of CO2 from the electricity generating
sector. See U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2020,
Table 2-4, at https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2020.
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 water, gas, or chemical injectants into oil and gas reservoirs to boost production (that is,
EOR) has been practiced in the oil and gas industry for several decades. CO2 is one type of
injectant that is used in EOR processes. 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 could potentially 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, depending on the process
characteristics and analysis methodologies used.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 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 USE IT Act and Energy Act of 2020. Both focus on

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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“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.

41 P.L. 116-260, Division S, §102(c).
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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 This process is similar to postcombustion carbon capture in some ways, though
DAC and CCS differ in a number of ways.
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 In 2021, DOE launched a research
effort called the Carbon Negative Shot, aiming to achieve CO2 removal (including DAC) for less than $100 per
ton.47 By comparison, some estimate costs for conventional CCS from coal-fired electricity generating plants in
the United States between $48 and $109 per ton.48
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).49 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.

42 CRS In Focus IF11501, Carbon Capture Versus Direct Air Capture, by Ashley J. Lawson. Some processes capture
CO2 from seawater instead of the atmosphere. These are sometimes called direct ocean capture, or DOC.
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.
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%. Duncan Leeson, Andrea Ramirez,
and Niall Mac Dowell, “Carbon Capture and Storage from Industrial Sources,” in Carbon Capture and Storage, ed.
Mai Bui and Niall Mac Dowell, p. 299.
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 DOE, “Secretary Granholm Launches Carbon Negative Earthshots to Remove Gigatons of Carbon Pollution From
the Air by 2050,” press release, November 5, 2021.
48 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.
49 For more information, see CRS In Focus IF11455, The Tax Credit for Carbon Sequestration (Section 45Q), by
Angela C. Jones and Molly F. Sherlock.
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Commercial CCS Facilities
According to one set of data collected by the Global CCS Institute (GCCSI), 24 commercial
facilities were capturing and injecting CO2 throughout the world in 2021, 12 of which are in the
United States.50 An additional facility, the Red Trail Energy facility, came online in the United
States in 2022. See Figure 6 for locations of U.S. projects capturing and injecting CO2 for either
EOR or geologic sequestration, some of which are not in operation.
Figure 6. Location of U.S. Carbon Capture and Injection Projects
EOR and Geologic Sequestration

Source: CRS, using data from the Global CCS Institute, Global Status Report 2021, 2021, and the University of
North Dakota Energy & Environment Research Center at undeerc.org.

50 Global CCS Institute, Global Status Report 2021, December 1, 2021; and North Dakota Industrial Commission,
Class VI - Geologic Sequestration Wells, accessed October 4, 2022, at https://www.dmr.nd.gov/dmr/oilgas/ClassVI .
The 13 facilities in operation do not include two facilities, Petra Nova and Lost Cabin, that stopped CCS operations in
2020, or the Zeros facility, which is under construction. 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.
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These facilities reportedly have a cumulative capacity to capture an estimated 40 million metric
tons of CO2 each year.51 Additionally, according to GCCSI, one commercial facility was under
construction and 15 projects were in advanced development in the United States, as of 2021.52
U.S. capture and injection facilities in operation or under development occur in seven industrial
sectors, according to GCCSI data: chemical production, hydrogen production, fertilizer
production, natural gas processing, and power generation.53 Until spring of 2022, the Archer
Daniels Midland (ADM) facility in Decatur, IL (also known as the Illinois Industrial Project), was
the only facility injecting CO2 solely for geologic sequestration. The facility injects CO2 captured
from ethanol production into a saline reservoir and as of 2021 reported that 2 million metric tons
of CO2 had been injected at the site.54 In 2022, North Dakota issued a Class VI permit for CO2
injection by Red Trail Energy in Richardton, ND. The company plans to capture and inject
180,000 tons of CO2 per year into an on-site formation for geologic sequestration.55 See Figure 7
for additional information on the timeline and industrial sectors for CO2 capture and injection
facilities in the United States.

51 Global CCS Institute, Global Status Report 2021, p. 62.
52 Global CCS Institute, Global Status Report 2021, pp. 63-64. GSSCI does not define “advanced development” in this
report.
53 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.
54 EPA FLIGHT database, accessed March 14, 2022.
55 Industrial Commission of North Dakota, “North Dakota Approves First Carbon Capture and Storage Project Under
State Primacy in the United States,” accessed August 1, 2022, at www.nd.gov/ndic/ic-press/News-DMR211019.pdf.
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Figure 7. Operational, Planned, and Suspended Facilities in the United States
Injecting CO2 for Geologic Sequestration and EOR

Source: CRS, adapted from Global CCS Institute, Global Status Report 2021, 2021; GSSCI does not define “advanced
development” in this report. Red Trail Energy information from the Industrial Commission of North Dakota.
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.
Stakeholders have paid particular attention 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 noted as examples
of carbon capture technology. At the same time, both projects have been criticized for high costs,
relative to other low-carbon technologies for electricity generation, and for sequestering carbon
via EOR.56 In May 2020, Petra Nova’s owners 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.57

56 See, for example, Food & Water Watch, “Top 5 Reasons Carbon Capture and Storage (CCS) Is Bogus,” July 20,
2021.
57 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.
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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
5,200 short tons (approximately 4,717 metric tons) of CO2 per day from its 240-megawatt-
equivalent slipstream using post combustion capture technology.58 The capture technology was
designed to be approximately 90% efficient (i.e., designed to capture about 90% of the CO2 in the
exhaust gas after the coal was burned to generate electricity) and was designed to capture 1.4
million metric tons of CO2 each year.59 The captured CO2 was transported via an 82-mile pipeline
to the West Ranch oil field, where it was 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 handled 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.60 However,
Petra Nova’s operators turned off the CCS equipment in May 2020, citing low oil prices caused,
in part, by the COVID-19 pandemic.61 In January 2021, the operators announced plans to
indefinitely shut down the CCS equipment’s power source.62 As of October 2022, Petra Nova
remains out of service.63
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.64 Petra Nova is the only
CCPI Round 3 project that expended its ARRA funding and began operating.65 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.66

58 Slipstream refers to the exhaust gases emitted from the power plant. U.S. Department of Energy (DOE), W.A. Parish
Post-Combustion CO2 Capture and Sequestration Demonstration Project Final Scientific/Technical Report, March 31,
2020, p. 3.
59 DOE, “Petra Nova CCS Project.”
60 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.
61 L.M.Sixel, “NRG Mothballs Carbon Capture Project at Coal Plant,” Houston Chronicle, July 31, 2020.
62 “Power Plant Linked to Idled U.S. Carbon Capture Project Will Shut Indefinitely,” Reuters, January 29, 2021,
https://finance.yahoo.com/news/power-plant-linked-idled-u-204526410.html.
63 Corbin Hiar and Carlos Anchondo, “Biggest CCS Failure Clouds Supreme Court Ruling,” E&E News, July 11, 2022.
64 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.
65 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.
66 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,67 cost
approximately $1.5 billion, according to one source, though it was originally estimated to cost
$1.3 billion.68 Of the originally estimated 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 been projected to cost as much as $3.8
billion. The larger-scale project was discontinued because of the escalating costs.69
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 March 2022, the plant had captured over 4.3 million metric tons of
CO2 since full-time operations began in October 2014.70 The project injected 370,000 metric tons
of CO2 for geologic sequestration as of 2021.71
The DOE CCS Program
DOE has funded R&D of aspects of the three main steps of an integrated CCS system since at
least 1997, primarily through its Fossil Energy and Carbon Management Research, Development,
Demonstration, and Deployment program (FECM).72 CCS-focused R&D has come to dominate
the coal program area within DOE FECM since 2010. Since FY2010, Congress has provided $9.2
billion (in constant 2022 dollars) total in annual appropriations for FECM (see Table 2).73

67 SaskPower is the principal electric utility in Saskatchewan, Canada.
68 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.
69 Ibid.
70 SaskPower, BD3 Status Update: March 2022, at https://www.saskpower.com/about-us/our-company/blog/2022/bd3-
status-update-march-2022.
71 Petroleum Technology Research Center, Annual Report 2020-2021, at https://ptrc.ca/pub/docs/annual-reports/
Annual%20Report%202020-21-%20Final_sm.pdf.
72 DOE has also funded some CCS and carbon removal research through its Advanced Research Projects Agency –
Energy. 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.
73 For information on FY2021 and FY2022 appropriations, see CRS In Focus IF11861, DOE’s Carbon Capture and
Storage (CCS) and Carbon Removal Programs, by Ashley J. Lawson.
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link to page 25 link to page 25
Table 2. Annual Appropriations for DOE Fossil Energy and Carbon Management (FECM)
Research, Development, Demonstration, and Deployment Program Areas
FY2010 through FY2022 (in thousands of nominal dollars)
FECM Program
Program/
Areas
Activity
FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 FY2016 FY2017 FY2018 FY2019 FY2020
FY2021
FY2022
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
86,300
99,000
Systems

Carbon Dioxide

40,000
49,000
Removal

Carbon

23,000
29,000
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
97,000

Advanced Energy
—
168,627
97,169
92,438
99,500
103,000
105,000
105,000
112,000
129,683
120,000
108,100
94,000
and Hydrogen
Systems

Cross-Cutting
—
41,446
47,946
45,618
41,925
49,000
50,000
45,500
58,350
56,350
56,000
32,900
33,000
Research

Mineral
—
—
—
—
—
—
—
—
—
—
—
53,000
53,000
Sustainability

Supercritical
—
—
—
—
—
10,000
15,000
24,000
24,000
22,430
16,000
14,500
15,000
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
0
Coal Pilotsa
Subtotal CCUS and
393,485 389,688 359,320 341,864 392,202 400,000 430,000
473,800
481,117
486,230
490,800
446,800
469,000
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
0
Technologies
CRS-19

FECM Program
Program/
Areas
Activity
FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 FY2016 FY2017 FY2018 FY2019 FY2020
FY2021
FY2022

Unconventional
19,474
0
4,859
4,621
15,000
4,500
20,321
21,000
40,000
46,000
46,000
46,000
0
Fossil Energy
Technologies
from Petroleum
– Oil
Technologies

Resource

110,000
Technologies and
Sustainability

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
66,800
Direction

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

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
1,001
Recruitment

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

NETL
—
—
—
—
—
—
0
40,500
45,000
45,000
50,000
55,000
75,000
Infrastructure

Coop R&D
4,868
—
—
—
—
—
—
—
—
—

Directed
35,879
—
—
—
—
—
—
—
—
—

20,199
Projects
Subtotal Other

266,285 195,364 164,754 156,851 178,229 171,000 202,000
208,200
245,700
253,770
259,200
303,200
356,000
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
825,000
Total FECM (Q2

2022 dollars)
832,547 533,715 409,144 598,581 669,712 669,402 740,721
766,636 809,515 809,032 800,863 781,295 825,000

CRS-20

Sources: U.S. Department of Energy annual budget justifications for FY2012 through FY2023; explanatory statement for P.L. 115-141, Division D (Consolidated
Appropriations Act, 2018, at https://rules.house.gov/bil /115/hr-1625-sa); explanatory statement for P.L. 117-30 (Consolidated Appropriations Act, 2022, Division D).
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
FY2022 appropriations; previous appropriations language used alternative names for some program areas and may not be completely comparable. Supplemental
appropriations provided by the American Recovery and Reinvestment Act of 2009 (ARRA; P.L. 111-5) and the Infrastructure Investment and Jobs Act (IIJA; P.L. 117-58)
are not shown in the table. The carbon utilization program was first authorized for FY2021 as part of P.L. 116-260. The line items for Carbon Dioxide Removal and
Resource Technologies and Sustainability were first used in FY2022 appropriations. Nominal dol ars adjusted to Q2 2022 dol ars using the price index for federal
government investment in research and development from Bureau of Economic Analysis, “National Income and Product Accounts,” Table 3.9.4.
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.

CRS-21

link to page 26 Carbon Capture and Sequestration (CCS) in the United States

Congress has additionally provided supplemental funding for DOE’s CCS activities. The
American Recovery and Reinvestment Act of 2009 (ARRA; P.L. 111-5) provided an additional
$3.4 billion ($4.4 billion in 2022 dollars), specifically for CCS projects.74 The Infrastructure
Investment and Jobs Act (IIJA; P.L. 117-58) provided $8.5 billion (nominal dollars) in
supplemental funding for CCS for FY2022-FY2026 (see Table 3), including funding for the
construction of new carbon capture facilities and commercial carbon storage facilities.
Additionally, IIJA provided $3.6 billion (nominal dollars) in supplemental funding for DAC,
primarily to support the establishment of four regional direct air capture hubs in the United
States.75
Table 3. Infrastructure Investment and Jobs Act Supplemental Appropriations for
Carbon Capture and Storage Programs
FY2022 through FY2026 (in thousands of nominal dollars)
Total
Unspecified
FY2022-
Program
Year
FY2022
FY2023
FY2024
FY2025
FY2026
FY2026
Front-End
Engineering and
Design (carbon

20,000
20,000
20,000
20,000
20,000
100,000
capture)
Carbon Capture
Large-Scale Pilot

387,000
200,000
200,000
150,000
—
937,000
Projects
Carbon Capture
Demonstration

937,000
500,000
500,000
600,000
—
2,537,000
Projects
Carbon Dioxide
Transportation
Infrastructure
Finance and

3,000
2,097,000
—
—
—
2,100,000
Innovation
(CIFIA)
Carbon Utilization

41,000
65,250
66,563
67,941
69,388
310,141
Carbon Storage
Validation and

500,000
500,000
500,000
500,000
500,000
2,500,000
Testing
U.S.
Environmental
Protection Agency
50,000
5,000
5,000
5,000
5,000
5,000
75,000
Class VI Injection
Well Program
Source: Infrastructure Investment and Jobs Act (IIJA; P.L. 117-58), Division J.

74 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.
75 The Infrastructure Investment and Jobs Act (IIJA; P.L. 117-58) defined a regional direct air capture hub as “a
network of direct air capture projects, potential carbon dioxide utilization off-takers, connective carbon dioxide
transport infrastructure, subsurface resources, and sequestration infrastructure located within a region.” 42 U.S.C.
§16298d(j).
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Notes: Programs are within the U.S. Department of Energy (DOE), except for the U.S. Environmental
Protection Agency’s (EPA’s) Class VI injection well program, which permits wells for geological sequestration of
carbon dioxide. Some DOE programs are administered by the Office of Fossil Energy and Carbon Management
(FECM), while others are administered by the Office of Clean Energy Demonstrations. IIJA additionally provided
$3,500,000,000 ($700 mil ion each year, FY2022-FY2026) to develop four regional clean direct air capture hubs
and $115 mil ion (unspecified year) for direct air capture technology prize competitions. Both programs are to
be administered by FECM. All funds are to remain available until expended.
A 2021 evaluation by the Government Accountability Office (GAO) found several cost control
risks related to DOE’s past management of its CCS program, particularly DOE’s implementation
of ARRA.76 These risks included a high-risk selection process, an accelerated schedule of project
review, and the bypassing of internal cost controls. GAO found DOE used less risky processes in
awarding CCS funding for industrial projects as compared to coal projects. Partly as a result, two
out of three funded industrial CCS projects were operational in 2021, while none of the eight
funded coal projects was operational. GAO noted that economic factors, such as declines in
natural gas prices, affected coal projects more than industrial projects, and also contributed to
withdrawal or cancellation of DOE-funded coal projects.
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.77 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. There are more than 119,500 EOR wells in the United States,
predominantly in California, Texas, Kansas, Illinois, and Oklahoma.78 This total includes EOR
wells that can be used to inject CO2 captured from anthropogenic sources and wells using
naturally derived CO2. Class VI wells are used to inject CO2 for geologic sequestration. Two
EPA-permitted Class VI wells are currently operating for sequestration in the United States, both
located at the ADM facility in Illinois.79 In 2022, North Dakota, which has delegated authority for
its UIC Class VI well program, issued two CO2 injection permits for geologic sequestration.

76 U.S. Government Accountability Office, Carbon Capture and Storage: Actions Needed to Improve DOE
Management of Demonstration Projects, December 2021.
77 40 C.F.R. §§144-147.
78 EPA, FY19 State UIC Injection Well Inventory, accessed April 11, 2021.
79 EPA has granted North Dakota and Wyoming primary enforcement authority for Class VI well programs in those
states.
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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.80 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.
The 45Q Tax Credit for Carbon Sequestration81
Federal tax credits for carbon sequestration were first authorized in 2008 with the enactment of the Energy
Improvement and Extension Act (Division B of P.L. 110-343). This act added Section 45Q to the Internal Revenue
Code (I.R.C), which established tax credits for CO2 disposed of in “secure geologic storage” or through EOR with
secure geologic storage.82 The Bipartisan Budget Act of 2018 (BBA; P.L. 115-123) amended Section 45Q to
increase the tax credit for capture and sequestration of “carbon oxide,” for its use as a tertiary injectant in EOR
operations, or for other qualified uses. In 2022, the measure known as the Inflation Reduction Act of 2022 (IRA;
P.L. 117-169) made numerous changes to Section 45Q.
Provisions in Section 45Q establish the amount of the tax credit per ton of carbon oxide captured and disposed
of, annual CO2 capture minimums, deadlines for beginning facility construction, and credit claim periods, and
direct the U.S. Department of Treasury (Treasury) to issue 45Q regulations, among other provisions. Credit
rates, capture minimums, and other provisions differ depending on the type of facility and when the facility or
capture equipment was placed in service.
The IRA established the tax rate for facilities or equipment placed in service after December 31, 2022. If projects
pay prevailing wages and meet registered apprenticeship requirements, the tax credit amount is $85 per ton of
CO2 disposed of in secure geologic storage and $60 per ton of CO2 used for EOR and disposed of in secure
geologic storage, or utilized in a qualified matter.83 For DAC facilities or equipment placed in service after
December 31, 2022, that pay prevailing wages and meet registered apprenticeship requirements, the credit is $180
per ton for CO2 disposed of in secure geologic storage and $130 per ton for CO2 that is used for EOR and
disposed of in secure geologic storage, or utilized in a qualified manner.84 Credit amounts are adjusted for inflation
after 2026. To qualify for tax credits, a point source facility or DAC facility must begin construction by December
31, 2032.85 The credit can be claimed over a 12-year period after operations begin.
The IRA increased the credit from the rates that had been established in the BBA. Before the IRA, and for facilities
placed in service before 2023, the Section 45Q tax credit amount increases linearly from $22.66 to $50 per ton
over the period from calendar year 2017 until calendar year 2026 for CO2 captured and disposed of in secure
geologic storage, and from $12.83 to $35 per ton over the same period for CO2 captured and used as a tertiary
injectant for EOR or for another qualified use, with tax credit amounts adjusted for inflation after 2026.
A facility must capture a minimum amount of CO2 to qualify for tax credits under Section 45Q.86 For facilities that
begin construction after August 16, 2022, DAC facilities must capture at least 1,000 tons of CO2 per year;

80 40 C.F.R. §144.19.
81 For additional background, see CRS InFocus IF11455, The Tax Credit for Carbon Sequestration (Section 45Q), by
Angela C. Jones and Molly F. Sherlock.
82 26 U.S.C §45Q. P.L. 115-123 expanded the tax credit to all carbon oxides, which includes CO2 and carbon
monoxide.
83 P.L. 117-169, §13104(b). For facilities that do not meet prevailing wage and apprenticeship requirements, the base
credit amount is $17 per ton for secure geologic storage and $12 per ton for EOR or other qualified use.
84 P.L. 117-169, §13104(c). Prior to the IRA amendments, eligible taxpayers disposing of CO2 captured through DAC
would have received the credit amount for the type of disposal used, either geologic sequestration or EOR/utilization.
For facilities or equipment placed in service after December 31, 2022, the base credit amount established in the IRA is
$36 per ton for CO2 captured using DAC with geological sequestration and $26 per ton for CO2 captured using DAC
with EOR or qualified utilization.
85 P.L. 117-169, §13104(a).
86 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
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electricity generating facilities must capture at least 18,750 tons of CO2 per year and have a capture design
capacity at least 75% of the unit’s baseline carbon oxide production; and other facilities must capture at least
12,500 tons of CO2 per year.87 The amounts established in the IRA are less than what had previously been
required. For facilities that began construction by August 16, 2022, and are covered under the BBA, an electricity
generating facility that emits more than 500,000 tons of CO2 per year 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.
Tax-exempt entities, including state and local governments and electric cooperatives, can elect to receive the
Section 45Q tax credits as “direct pay.” This allows these entities to receive the credit amount as a payment,
instead of a reduction in tax liability. The IRA allows direct pay for CO2 captured at facilities placed in service after
December 31, 2022. Taxpayers also may be able to elect to receive the Section 45Q tax credit as direct pay, for
up to five years, but not after 2032. Taxpayers can also elect to make a one-time transfer of the credit. For
equipment placed in service after February 9, 2018, the credit is attributable to the person who 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 who disposes of or uses the qualified CO2.
Some stakeholders have suggested that the tax credit increases in Section 45Q could be a “game changer” for
CCS developments in the United States, by providing incentives sufficient to drive investments in CO2 capture and
storage.88 They note that EOR has been the main driver for CCS development, 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.89 Another factor to
consider is the cost. Over the FY2022-FY2031 budget window, Treasury estimates that the tax credit wil reduce
federal income tax revenue by a total of $20.1 bil ion.90 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). The IRS may issue further Section 45Q guidance related to changes enacted
in the IRA in the future.

Department of the Treasury, “Credit for Carbon Oxide Sequestration,” 85 Federal Register 34050-34075, June 2, 2020.
87 P.L. 117-169, §13104(a). For equipment placed in service after the enactment of the BBA on February 9, 2018, and
before January 1, 2023, the annual capture requirements are (1) in the case of a facility that emits no more than 500,000
metric tons of carbon oxide, capture at least 25,000 metric tons of carbon oxide that is either fixated through the
growing of algae or bacteria, chemically converted into a material or chemical compound in which the carbon oxide is
stored, or used for another commercial purpose (other than a tertiary injectant); (2) in the case of an electricity
generating facility not described in (1), capture at least 500,000 metric tons of carbon oxide per year; or (3) in the case
of a direct air capture facility not described in (1) or (2), capture at least 100,000 metric tons of carbon oxide. For
equipment placed in service before February 9, 2018, the capture requirement is 500,000 tons per year.
88 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.
89 Natural Resources Defense Council, “Capturing Carbon Pollution While Moving Beyond Fossil Fuels,” accessed 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.
90 U.S. Department of the Treasury, “FY2023 Tax Expenditures,” accessed February 17, 2022, at
https://home.treasury.gov/policy-issues/tax-policy/tax-expenditures.
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Discussion
In recent Congresses, proposed and enacted CCS-related legislation has addressed federal CCS
research and development (R&D) activities and funding, CO2 pipelines, and the carbon
sequestration tax credit. Bills, or provisions thereof, addressing CCS 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 and beyond.
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).91 The law also authorized a DOE carbon utilization research
program and specific activities related to direct air capture (e.g., a DAC technology prize). IIJA
built upon this expanded scope, providing supplemental appropriations for several programs
authorized by P.L. 116-260, and established new CCS and DAC programs. 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.92
Council on Environmental Quality 2021 CCS Report to Congress
and 2022 CCS Guidance
In response to the USE IT Act, in 2021, the White House Council on Environmental Quality
(CEQ) provided Congress with a report on carbon capture, utilization, and sequestration project
permitting and review.93 One of several reports required by Congress in the Consolidated
Appropriations Act, 2021 (P.L. 116-260), this report provides information on federal permitting
and regulations for CCS projects and examines technical, financial, and policy-related issues for
project deployment. In its key findings, CEQ states that “CCUS has a critical role to play in
decarbonizing the global economy” and that “President Biden is committed to accelerating the
responsible development and deployment of carbon capture, utilization, and permanent
sequestration as needed to decarbonize the U.S. economy by mid-century.”94 CEQ also finds that
to be beneficial, CCS projects must be “well-designed and well governed.”95 Regarding
governance, CEQ also finds that the existing federal regulatory framework is “rigorous and
capable of managing permitting and review actions while protecting the environment, public
health, and safety as CCUS projects move forward.”96
In February 2022, CEQ released an interim guidance, Carbon Capture, Utilization, and
Sequestration Guidance, also as directed by Congress in the USE IT Act.97 The interim guidance

91 For additional information, see CRS In Focus IF11861, DOE’s Carbon Capture and Storage (CCS) and Carbon
Removal Programs, by Ashley J. Lawson.
92 See, for example, Heritage Foundation, “Eliminate the DOE Office of Fossil Energy,” in Budget Blueprint for
FY2022.
93 CEQ, Council on Environmental Quality Report to Congress on Carbon Capture, Utilization, and Sequestration,
https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf. The report to Congress
is required by P.L. 116-260, Division S, §102.
94 CEQ CCS Report, p. 8.
95 CEQ CCS Report, p. 8.
96 CEQ CCS Report, p. 8.
97 Council on Environmental Quality, “Carbon Capture, Utilization, and Sequestration Guidance,” 87 Federal Register
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includes recommendations for federal agencies that would support “the efficient, orderly, and
responsible development and permitting of CCUS projects at an increased scale in line with the
Administration’s climate, economic, and public health goals.”98 In the document, CEQ provides
guidance to federal agencies on the processes for permitting and review of CCS projects and CO2
pipelines, public engagement, and assessing environmental impacts of CCS projects.
Other CCS Policy Issues
With respect to other issues for congressional consideration, 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 and
P.L. 117-169 also extended the start of construction deadline for facilities claiming the 45Q tax
credit. 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.
The issue of expanded CCS deployment is closely tied to the issue of reducing greenhouse gas
emissions to mitigate human-induced climate change. In 2021, the Biden Administration
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 two executive orders signed in January 2021, 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.99 At this early stage, the implications of these executive branch policies and actions on
CCS project development and deployments are unclear.
The use of CCS technology as a greenhouse gas emissions reduction approach is not uniformly
supported by advocates for actions to address climate change.100 Some argue that CCS supports
continued reliance on fossil fuels, which runs counter to their view of how to reduce greenhouse
gas emissions and meet other environmental goals. They tend to prefer policies that phase out the
use of fossil fuels altogether. Others raise concerns about the long-term safety and environmental
uncertainties of injecting large volumes of CO2 underground.

8808-8811, February 16, 2022. The CEQ guidance is required by P.L. 116-260, Division S, §102.
98 Council on Environmental Quality, “Carbon Capture, Utilization, and Sequestration Guidance,” 87 Federal Register
8808-8811, February 16, 2022, p. 8809.
99 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.
100 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.
Congressional Research Service

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Carbon Capture and Sequestration (CCS) in the United States

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
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Congressional Research Service
R44902 · VERSION 12 · UPDATED
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