Carbon Capture and Sequestration (CCS) in the United States

Congressional research reportOct 5, 2022

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Carbon Capture and Sequestration (CCS)

in the United States

Updated October 5, 2022

Congressional Research Service

https://crsreports.congress.gov

R44902

SUMMARY

Carbon Capture and Sequestration (CCS) in the

United States

Carbon 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 permanently underground. As one

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

industrial facilities. The concept of carbon utilization has also gained interest within Congress

and in the private sector as a means for capturing CO 2 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 CO 2 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.

R44902

October 5, 2022

Angela C. Jones

Analyst in Environmental

Policy

Ashley J. Lawson

Analyst in Energy Policy

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 CO 2,” 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 CO 2 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 CO 2 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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Carbon Capture and Sequestration (CCS) in the United States

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

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 capitalintensive 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 CO

2 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 CO 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 CO from the flue gas. When the CO -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

Steam

Turbine

Generator

Flue gas

to atmosphere

Electricity

Coal

Air

PC Boiler

Air Pollution

Control Systems

(NOx, PM, SO2)

CO2 Capture Mostly

Amine

Stack

Steam

Amine/CO2

Separation

CO2

Compression

CO2 to

storage

Source: E. S. Rubin, “CO2 Capture and Transport,” Elements, vol. 4 (2008), pp. 311-317.

Notes: Other major air pollutants (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

Electricity

Flue gas

to atmosphere

Air

H2O

Coal

H2O

Gasifier

Quench

System

Shift

Reactor

H2 Gas Turbine

Sulfur

CO2 Capture

Combined

Removal CO2

Cycle Plant

Selexol

Sulfur

Recovery

Stack

Air

Separation

Unit

Selexol/CO2

Separation

CO2

Compression

CO2 to

storage

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

Steam

Turbine

Generator

Electricity

Stack

Flue gas

to atmosphere

Steam

Coal

Air Pollution

CO2

Control Systems

H2O

( PM, SO2)

PC Boiler

Distillation

System

CO2

Compression

CO2 to

storage

Flue gas recycle

H2O

Air

Separation

Unit

Air

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 CO

2 refers to temperature and pressure conditions above a critical point where CO 2 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-reportmileage-hazardous-liquid-or-carbon-dioxide-systems.

24 For additional information on CO 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 CO , 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

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-V2015.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 CO 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 will exceed the low

estimate and a 10% probability that the estimated storage volume will 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 CO 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 CO 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-oiland-gas-related-injection-wells.

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Carbon Capture and Sequestration (CCS) in the United States

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 CO

2 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 CO for EOR or enhanced natural gas recovery.

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Carbon Capture and Sequestration (CCS) in the United States

“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/carbonutilization.

41 P.L. 116-260, Division S, §102(c).

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Carbon Capture and Sequestration (CCS) in the United States

Direct Air Capture

Direct air capture (DAC) is an emerging set of technologies that aim to remove CO 2 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 CO 2 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 CO 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 CO , the higher the cost to extract it, because much larger volumes

are required to be processed. By comparison, the concentration of CO 2 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-carbontechnologies-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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Carbon Capture and Sequestration (CCS) in the United States

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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Carbon Capture and Sequestration (CCS) in the United States

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 CO 2

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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Carbon Capture and Sequestration (CCS) in the United States

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 = million 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.

Congressional Research Service

Carbon Capture and Sequestration (CCS) in the United States

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 industrialscale 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-megawattequivalent 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=irolnewsArticle&ID=2236424.

61 L.M.Sixel, “NRG Mothballs Carbon Capture Project at Coal Plant,” Houston Chronicle, July 31, 2020.

“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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Carbon Capture and Sequestration (CCS) in the United States

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 300megawatt 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/bd3status-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-newvision.

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.

Congressional Research Service

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

Areas

CCUS and Power

Systems

Program/

FY2010

FY2011

FY2012

FY2013

FY2014

FY2015

FY2016

FY2017

FY2018

FY2019

FY2020

FY2021

FY2022

—

58,703

66,986

63,725

92,000

88,000

101,000

100,671

117,800

86,300

99,000

Carbon Dioxide

Removal

40,000

49,000

Carbon

Utilization

23,000

29,000

Activity

Carbon Capture

Carbon Storage

—

120,912

112,208

106,745

108,766

100,000

106,000

95,300

98,096

100,000

79,000

97,000

Advanced Energy

and Hydrogen

Systems

—

168,627

97,169

92,438

99,500

103,000

105,000

112,000

129,683

120,000

108,100

94,000

Cross-Cutting

Research

—

41,446

47,946

45,618

41,925

49,000

50,000

45,500

58,350

56,350

56,000

32,900

33,000

Mineral

Sustainability

—

53,000

Supercritical

CO2 Technology

—

10,000

15,000

24,000

22,430

16,000

14,500

15,000

NETL Coal R&D

—

35,011

33,338

50,011

50,000

53,000

54,000

61,000

Transformational

Coal Pilotsa

—

50,000a

35,000

25,000

20,000

10,000

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

17,364

14,575

13,865

20,600

25,121

43,000

50,000

51,000

57,000

Subtotal CCUS and

Power Systems

Other FECM

CRS-19

Natural Gas

Technologies

FECM Program

Areas

Program/

Activity

FY2010

FY2011

FY2012

FY2013

FY2014

FY2015

FY2016

FY2017

FY2018

FY2019

FY2020

FY2021

FY2022

Unconventional

Fossil Energy

Technologies

from Petroleum

– Oil

Technologies

19,474

4,859

4,621

15,000

4,500

20,321

21,000

40,000

46,000

Resource

Technologies and

Sustainability

Subtotal Other

FECM

Rescissions/Use of

Prior-Year Balances

110,000

Program

Direction

158,000

164,725

119,929

114,201

120,000

119,000

114,202

60,000

61,070

61,500

Plant and Capital

20,000

19,960

16,794

15,982

16,032

15,782

—

Env. Restoration

10,000

9,980

7,897

7,515

5,897

7,995

—

Special

Recruitment

700

699

700

667

700

1,001

NETL Research

and Operations

—

43,000

50,000

83,000

NETL

Infrastructure

—

40,500

45,000

50,000

55,000

75,000

Coop R&D

4,868

—

Directed

Projects

35,879

—

266,285

195,364

164,754

156,851

178,229

171,000

202,000

208,200

245,700

253,770

—

(14,000)

—

(151,000) (187,000) —

66,800

20,199

259,200

303,200

356,000

Total FECM

659,770

434,052

337,074 498,715

570,431

571,000

632,000

668,000

726,817

740,000

750,000

825,000

Total FECM (Q2

2022 dollars)

832,547

533,715

409,144

669,712

669,402

740,721

766,636

809,515

809,032

800,863

781,295

825,000

CRS-20

598,581

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/bill/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 dollars adjusted to Q2 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.

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

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)

FY2022

FY2023

FY2024

FY2025

FY2026

Total

FY2022FY2026

Front-End

Engineering and

Design (carbon

capture)

20,000

100,000

Carbon Capture

Large-Scale Pilot

Projects

387,000

200,000

150,000

—

937,000

Carbon Capture

Demonstration

Projects

937,000

500,000

600,000

—

2,537,000

Carbon Dioxide

Transportation

Infrastructure

Finance and

Innovation

(CIFIA)

3,000

2,097,000

—

2,100,000

Carbon Utilization

41,000

65,250

66,563

67,941

69,388

310,141

Carbon Storage

Validation and

Testing

500,000

2,500,000

5,000

75,000

Program

U.S.

Environmental

Protection Agency

Class VI Injection

Well Program

Unspecified

Year

50,000

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 million each year, FY2022-FY2026) to develop four regional clean direct air capture hubs

and $115 million (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 CO 2 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 CO 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 CO 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 CO 2. 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 CO 2 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 coalfired 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 will reduce

federal income tax revenue by a total of $20.1 billion.90 Other groups note that measures in addition to the 45Q

tax credits will 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

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-beyondfossil-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.

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Author Information

Angela C. Jones

Analyst in Environmental Policy

Ashley J. Lawson

Analyst in Energy Policy

Acknowledgments

CRS Specialist Paul Parfomak provided substantial contributions to the CO 2 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

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R44902 · VERSION 12 · UPDATED

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