Carbon capture and sequestration: Roadblocks and opportunities in the US market

Carbon capture and sequestration (CCS) refers to the capture of carbon dioxide emissions at their source and the subsequent transport and geological sequestration of those emissions into storage wells deep underground. The CO2 is generally sequestered at least 3,000 feet or so below the surface, at depths well below the water table or other energy-related activities like mining, oil and gas production, or geothermal energy production. Storage is intended to be permanent. Thus, long-term monitoring is critical and is an inextricable part of the related permitting for such wells. In this paper, we focus specifically on the carbon management market that exists within the CCS ecosystem.

CCS can help decarbonize a wide variety of activities, including in hard-to-decarbonize sectors. Indeed, the Intergovernmental Panel on Climate Change considers its use essential, writing: “The deployment of [CCS] to counterbalance hard-to-abate residual emissions is unavoidable if net zero CO2 or [greenhouse gas] emissions are to be achieved.” The International Energy Agency (IEA) sees carbon capture as necessary to achieving net zero emissions by 2050, calculating that roughly 1,000m metric tons of carbon dioxide capture capacity is necessary by 2030 to achieve that goal. By comparison, global operating capacity today is ~50m metric tons per annum, of which the US represents some 22m metric tons, underscoring the large gap in capacity if those targets are to be achieved.

CCS is poised for a period of potentially tremendous growth in the US. The Inflation Reduction Act (IRA) and the Infrastructure Investment and Jobs Act (IIJA), passed in 2022 and 2021, respectively, contain various incentives aimed at supporting carbon management technologies, and CCS specifically. These incentives are not only tax credits. They also include funding opportunities for building out pipelines, supporting demonstration programs across decarbonizing industry, and developing clean hydrogen projects, among others. There are also other policy measures that directly or indirectly support CCS, including state-level clean fuels programs, which encourage production of low carbon intensity (CI) fuels.

Since the introduction of these pieces of legislation, more than 120 carbon capture projects have been announced. Ultimately, not all announcements will translate into final investment decisions. Some projects will have competitive advantages based on their infrastructure needs, partnership structure, location, and other factors.

Carbon capture is not a new technology. It has been commercialized in the United States for some five decades, primarily to support enhanced oil recovery and integrated syngas capture at ammonia plants for urea production.[1] Because of that historical use, the US has the world’s highest carbon capture capacity at some 22m metric tons per annum across 15 facilities and some 5,200 miles of carbon dioxide pipe, the largest network in the world. The U.S. Geological Survey estimates that there is 3,000 metric gigatons of subsurface CO2 storage capacity that is technically accessible onshore and in state waters.

Carbon capture technology has already been installed at hydrogen steam methane reformers, existing fertilizer plants, coal-fired power plants, and ethanol plants (see figure 1).

[1] When captured carbon is utilized as part of a process it is referred to as carbon capture and utilization (CCU), or carbon capture, utilization and storage (CCUS). Enhanced oil recovery and fertilizer applications are examples of CCU/CCUS. Enhanced oil recovery wells are typically governed by a Class II permit.

For carbon capture technology to be commercialized widely beyond the footprint it occupies today, potential market participants must get more comfortable with two key project elements: cost and operational success. Comfort with cost will be supported by the extent to which projects are delivered to completion “on cost” – without significant cost overruns – and to the extent that the scaling of technology brings down the cost of subsequent similar projects. CCS remains an expensive technology given that the industry has yet to reach scalability and, in some cases, is still reliant on retrofits to install capture systems rather than modular construction. Projects may in the future become more repeatable or more modular, and allowing supply chains to develop around them will help scale cost. In turn, falling costs should open up the ecosystem to more participants. In terms of operational success, potential market participants need confidence that projects ultimately are able to deliver on their stated carbon capture percentage and project uptime.

Various incentives and credits stemming from existing federal and state policies can be stacked to help support the economics of carbon capture. This so-called “policy stack” is not unique to carbon capture. It has been instrumental in helping the development of biofuels in the US, for example. The 45Q tax credit is most closely associated with carbon capture. This credit was expanded under the IRA, but there are several other IRA credits that are also linked to carbon capture.

The 45Q tax credit was originally introduced in 2008, then broadened in 2018 under the Bipartisan Budget Act, before being further expanded by the IRA. The IRA increased the credit’s value assuming prevailing wage and apprenticeship requirements are met (see figure 2). However, if those requirements are not met, the credit value actually falls substantially below its prior value. The IRA also decreased the minimum plant size eligible for the credit, thereby broadening its applicability. The 45Q tax credit is available to qualifying projects for a period of 12 years and can be directly paid for the first five years of project eligibility. If a project elects direct pay, it could reduce its need for tax equity investment. The market for tax equity is highly competitive. It comprises only USD 20bn to USD 25bn annually in the US and typically favors larger developers with existing tax equity relationships over smaller market participants or those pursuing less established technologies.

If projects are producing blue hydrogen – that is, is hydrogen produced with the addition of CCS to store carbon oxide byproducts – they can instead elect to receive the IRA’s 45V tax credit for clean hydrogen production. Unlike many IRA credits, the 45V and 45Q cannot be stacked and a project must elect to claim only one.

The IRA 45Z credit (Clean Fuel Production Credit) is a credit related to plant output applicable to fuels produced from 2025 to 2027. Like the 45V credit, the 45Z cannot be stacked with the 45Q credit. However, it remains an attractive option for fuel production from ethanol plants and for related derivative products like alcohol-to-jet-derived sustainable aviation fuel. Indeed, the ethanol industry’s interest in this avenue of decarbonization is underscored by the more than 60 plants that hope to connect to announced greenfield and converted carbon dioxide pipeline capacity in the US.

The California Low Carbon Fuel Standard (LCFS) and other state clean fuels programs grant suppliers of low carbon intensity (CI) fuels credits with variable values generally tied to the fuel’s CI score. The direct link of credit generation to carbon intensity score is driving the potential adoption of CCS. The California LCFS allows CCS-linked projects to operate in that compliance market under two pathways. Under the fuel pathway, CCS can be used to reduce the carbon intensity of fuels, including ethanol and renewable diesel production. Under the project pathway, CCS reduces emissions in the supply chain, for example, in conjunction with steam methane reforming, and is eligible assuming the fuel is sold in California. Before generating LCFS credits in the California LCFS markets, participants must obtain permanence certification for their CCS project. Permanence certification requires complete compliance with the CCS Protocol, including 100 years of monitoring post-injection versus a 50-year minimum period for class VI wells.

Oregon and Washington have also established clean fuels programs modeled on California’s. New Mexico recently passed a clean fuel standard. New York, Illinois, Michigan, Massachusetts, Vermont, and New Jersey have also considered the possible introduction of clean fuels programs.

While outside of the policy stack, voluntary carbon markets can provide additional revenue streams if projects elect to monetize credits through the sale of carbon dioxide removal credits (CDRs). Red Trail Energy CCS, which started commercial operation in June 2022, became the first ethanol plant in the US to issue CDR credits for the voluntary carbon market. Summit Carbon Solutions, the proposed developer of one of the announced long-haul pipelines in the US, has partnered with Anew Climate to market CDRs from its proposed capture, transport, and storage projects.

In many cases, CDR buyers tend to be large corporates looking for emissions management mechanisms. In some cases, these also remain expensive for buyers, with CDR prices at USD 200 to 1,600/metric ton depending on removal type.

At present, a key governor of the time to market for CCS projects is securing a Class VI well permit, which is required to inject carbon dioxide into geologic formations for long-term carbon storage. The Environmental Protection Agency (EPA) has the authority to grant Class VI well permits and the authority to delegate that primary enforcement authority, or primacy, to states or tribes under the Underground Injection Control program of the federal Safe Drinking Water Act (SDWA). The permitting process is designed to be stringent (see figure 3). It includes site characterization to understand if a site has acceptable geology to allow C02 sequestration. There are also construction requirements to ensure the integrity of the well and prevent leakage, testing and monitoring requirements, and a process to report results to the relevant permitting authority to ensure compliance. The permitting process also includes emergency response, remediation plans, and requirements for financial instruments to support those.

There have been four draft permits and two final permits approved at the federal level since we last published on the state of the permit queue, but the backlog at the federal level remains sizeable, even with the movement of some 60 permits out of EPA’s federal permit queue to Louisiana’s jurisdiction now that it has gained state primacy (see figure 4). While the EPA announced in late 2022 that it would issue permits on an approximate two-year timeline, in reality, securing a permit has taken as long as six years at the federal level.

The length of the federal-level Class VI permitting process can impact the development of the industry, as has been noted. In early April, for example, members of the House Climate Solutions Caucus sent a letter to the EPA asking the agency to explain why there continue to be delays in permitting projects despite federal support, including funding and recent EPA staff additions. The letter cited that those delays were “actively crippling US efforts to deploy vital clean energy and carbon capture infrastructure alike.”

State primacy in issuing Class VI well permits can help streamline the process. In order to receive Class VI primacy, a state or tribe’s program must be at least as stringent as the EPA’s. The state or tribe must also have the capability to enforce penalties to protect the SDWA. Much like the Class VI individual well permit process, the review for state primacy is also known for its thoroughness and potential long lead time. Wyoming was granted class VI primacy in less than a year, but that apparent speed masks the effort the state took to communicate with its relevant EPA regional authority, EPA Region 8, ahead of the formal application process. For North Dakota, the process took over four years. For Louisiana, the process took just over two years, concluding in 2023.

North Dakota issued its first class VI permit – to Red TrailEnergy – in less than five months. The Louisiana Department of Natural Resources, which was granted Class VI primacy in late December 2023, indicated it expected permit issuance to take six to nine months – potentially placing some wells to receive permits before the close of the year. Louisiana represents some 50 million metric tons per annum (MTPA) of capacity seeking Class VI wells – pegging it only behind Texas at ~110 MTPA. If Louisiana’s estimated timeline is accurate, it could significantly change the landscape for CCS in the United States.

Though the Class VI permit is critical in bringing projects online, it may only represent one step in the process of fully permitting a project. In some areas a conditional use permit – which differs from the Class VI permit in that it tends to involve the surface use of land rather than subsurface – may be applicable when land is slated for use outside of typical zoning. In some cases, securing both the Class VI permit and the conditional use permit from the relevant local authority is necessary for a project to move forward.

Generally, there are two options for how to site carbon capture and sequestration projects. The first involves sequestration next to the site (or within the fence line). The second option is sequestration away from the site at a hub that sequesters carbon dioxide from multiple emitters. These could be multiple plants from the same corporate entity or from different corporate entities. The hub provides advantages of scale, including potential risk and cost reductions from shared infrastructure. It can also support smaller emitters’ participation in the system. The sequestration hub may be located in an area with appropriate geology near a high concentration of emitters, or it could be the final site at the end of a transport corridor that has tied in multiple emitters along its path. In some cases, a sequestration site may also have sufficient adjacent landholdings and infrastructure for emitters to locate facilities there as part of an industrial hub schematic.

The US has the largest carbon dioxide pipeline network in the world, but recently announced long-haul greenfield pipelines (see figure 5) to specifically service sequestration have faced delays. Permitting uncertainty, stakeholder and landowner opposition, and issues stemming from eminent domain have all been challenges. Such issues are not unique to carbon dioxide pipelines, with intrastate pipelines of varying fuel types facing the same issues. Consequently, some projects currently have a clear advantage, including projects that are able to use carbon capture as part of an integrated process, rely on an existing infrastructure footprint, secure right of way across a short route, or position themselves as large landholders sitting on appropriate sequestration geology. Without the development of pipeline infrastructure, the inclusivity of the technology is at risk. Otherwise, it will only be a viable option for projects with the geologic advantage of being located near appropriate sequestration sites or near existing infrastructure.

If the Class VI permit is foundational to carbon capture technology, the permitting regime for pipelines and other enabling infrastructure is also crucial. The Biden administration has asked Congress to provide federal authority in siting hydrogen and carbon dioxide pipelines and storage infrastructure. The IIJA also appropriated USD 2.1bn for low-interest loans and grants through the Carbon Dioxide Transportation Infrastructure Finance and Innovation (CIFIA) program for large-capacity projects.

We will cover the complexity of bringing carbon oxide pipeline infrastructure into service in a follow-up report.

Carbon dioxide emitters can generally be bucketed into two categories: high purity and low purity sources. High purity emissions streams refer to those with a highly concentrated carbon dioxide stream, like those associated with ethanol production and natural gas processing. Highly concentrated streams tend to make it easier and cheaper to separate carbon dioxide compared to low purity processes – like those at coal plants and cement plants – in which the carbon dioxide stream is comingled with other emissions. Furthermore, the higher the pressure of the emissions stream, the easier it is to capture. Thus, higher pressure streams tend to have lower costs, with ammonia production typifying such a stream. Scale also factors into cost, with capture more cost-effective at larger facilities than smaller ones. Various research pegs the range of costs for capturing CO2 at USD 15 to USD 120/Mt (see figure 6).

Existing carbon capture in the US has tended to occur in industries that are high purity or high pressure. Indeed, while there are potentially other drivers, including CDR monetization or higher credit generation potential in clean fuels programs, more than 60 existing ethanol plants in the US are seeking takeaway capacity on carbon dioxide pipelines in order to sequester their emissions.

For industries at the higher end of the carbon capture cost spectrum, various federal programs are seeking to help commercialize decarbonization technologies. In late March, the Department of Energy Loan Programs Office announced 33 projects selected for award negotiations for some USD 6bn for energy-intensive industry decarbonization. The focus is on high-emitting industries, including sequestration at one of the US’s largest cement plants.

As for CCS at power plants, the EPA’s final rulemaking on emissions for new, reconstructed, and existing fossil fuel-fired power plants now relies exclusively on CCS – rather than on low-greenhouse gas hydrogen as an avenue for compliance. Late last year when we covered the EPA’s proposed carbon pollution standards, we outlined the numerous potential challenges ahead for that proposal – several of which came to pass and likely ultimately led to revisions in the final rulemaking in late April. Indeed, a coalition of 25 states is now challenging the finalized rule, in addition to other lawsuits. If the rulemaking survives those challenges, it would potentially be a significant push forward for the carbon management industry.

At a fundamental level, there are two key ways to consider the “products” that emerge from carbon capture. An existing product, like ethanol, is able to achieve a much lower carbon intensity through carbon management. A new, “differentiated” greenfield product is created through the use of carbon capture like e-fuels or construction aggregates. For existing products, the use of carbon capture – and the ultimate accompanying reduction in carbon intensity – is offset or incentivized through various IRA-linked tax credits, compliance market credit generation, or CDRs. The market for differentiated products, on the other hand, is still nascent. The bearable cost premium associated with them is unknown, and in most cases long-term offtake for such differentiated products is non-existent. A firm’s own internal cost of carbon or other market mechanisms like carbon pricing could factor into how it weighs the cost premium in its decision-making process.

While the sheer number of announced CCS projects suggests that the industry is primed for growth, it is currently unclear how developed the differentiated products market will be, given these products’ higher cost compared to their conventionally produced counterparts. Ultimately, this could hamper the wider commercialization of the market. In some cases, the policy stack is making a concerted effort to help build demand for differentiated products, as was the case with Department of Energy’s Regional Clean Hydrogen Hubs program allocating USD 1bn for demand development in addition to helping support the build-out of the hydrogen projects themselves.

Though long-term offtake contracts for differentiated products are not a precondition to building a marketplace, they are generally pivotal for helping to secure traditional project funding. They allow project revenue streams to be substantiated and give developers and producers the confidence to move forward with projects by establishing known offtake.

In some cases, potential industry participants may be awaiting Class VI permit issuance. Before that, discussions around product offtake may seem premature.

From a stakeholder perspective, wider understanding of technology could help support commercialization. In some regions the technology has been operating for decades, but the general public may still be unfamiliar with it. Early and sustained engagement with effective dialogue is likely to be necessary for any project that hopes to move forward. That early engagement is also likely to include an educational component to help stakeholders gain an understanding of the technology. The stakeholder group is diverse and includes local communities, zoning commissions, public utilities commissions, landowners, regulators, and environmental groups, among others. In some cases engagement is embedded in processes relevant to carbon capture, for example, the public comment period for draft permits of EPA Class VI wells or the engagement required in order to receive DOE program funding for certain opportunities. In other cases, landowner and community engagement is necessary where there is no clear eminent domain authority. For projects that may be the first in their industry or community, the care with which engagement is taken and concluded is likely to have a significant impact on the success of the next project, and potentially on wider industry’s reputational risk. Setting a high bar on engagement, education, and ultimately on project execution can ultimately help the industry mature.