PAYNE INSTITUTE COMMENTARY SERIES: COMMENTARY

August 5, 2024

Authors

Brad Handler¹

Anna Littlefield^1,2

Lindene Patton³

Nicolas G. Perticari Pesci ²

Felix Ayaburi²

Siddhant Kulkarni²

Darshil Shah⁴

¹ Payne Institute for Public Policy, Colorado School of Mines

² Colorado School of Mines

³ Earth and Water Law, LLC

⁴ Rystad Energy

Acknowledgements

The authors gratefully acknowledge the support of the Carbon Capture Coalition/Great Plains Institute

Table of Contents

Executive Summary
Introduction
Risks and Operational Risk Mitigation
Preliminary Evaluation of Community-Oriented Risk Analysis
Financial Risk Management
Long Term Stewardship: Releasing Residual Liability
Conclusion: The Way Forward
Appendix I – Historical Risk Management Frameworks and Lessons for CCS
Appendix II – LTS Solution Considerations in UK And EU

Executive Summary

Carbon Capture and Storage (CCS) is widely considered an important tool in mitigating the global warming effects of excess CO₂ in the earth’s atmosphere. A critical piece of CCS is long term geological storage of captured CO₂.

The “ground rules” for responsible development of permanent geological CO₂ storage in the United States were laid out nearly 20 years ago, culminating in regulations, issued by the Environmental Protection Agency, that prescribed both the environmental and financial safeguards for project developers. These environmental safeguards were put in place to ensure, to the degree possible, that the stored CO₂ remains in its designated space. The financial safeguards, known as Financial Assurance (FA), requires that appropriate funds are set aside, or can be accessed, to address remediation of potential environmental damages resulting from (primarily) unforeseen CO₂ leakage.

With these rules in place, progress, as measured by the number of projects, was slowed by inadequate economics. Prospects for financial returns improved with the higher tax credits established by the Inflation Reduction Act and the number of applications for Class VI permits, i.e., projects that include permanent geological storage, now stands at 113.

The surge in new development effort has been accompanied by some shift in the nature of the project developer. Now 30% of the applications are sponsored by developers with little or no operating history.

These new developers throw into sharper relief the “other side of the coin” for project developers as they pursue CCS projects. That other side is financial risk management — and in particular the potential liability should the CO2 leak back to the surface/atmosphere during or after injection operations. New developers are more likely to lack the balance sheet to satisfy the EPA’s FA requirements. They are also likely to be far more reliant on Project Finance than others, which comes with different expectations about risk.

And these new developers are likely that much more likely to rely on commercial insurance, both to facilitate (raising financing for) geological storage projects and to meet FA requirements. Yet the fact that these developers lack operating history makes it that much harder for insurers to provide coverage — on top of the challenges the insurers face in assessing the risk of this relatively new “technology.” These developers have also, at least in some cases, sought long term commercial insurance contracts, which creates a further challenge for insurers, again because of limited history as well as how the insurance industry raises capital.

Finally, these developers exacerbate an overhang that exists for any CO₂ storage project: the idea that the developer is potentially liable for hundreds of years (or longer). This is well beyond the lifetime of the average corporation, but it can be particularly problematic for single purpose project financed companies.

Some developers have argued that a formal process to release them from liability during the Long Term Stewardship (LTS) phase of a geological storage project, which begins decades after injection has stopped, would be a helpful form of risk mitigation that could help catalyze projects.

Notably, it is widely thought that the risk of leakage declines over time once injection operations have ended due to pressure decrease with continued migration of the plume, solution trapping and (to a lesser degree) mineralization of the stored CO₂.

Yet the issue of developers’ retention vs. release of liability over the very long term remains contentious, with naysayers particularly focusing on the moral hazard such liability release creates. Such concerns appear to be overblown, for three reasons. First, the stringent environmental and FA requirements stipulated for Class VI wells — in effect construct a “storage security pyramid”. Second, developers have decades-long obligations before any such release of liability would be effected. Third, caveats can be put in place to address, for example, deficiencies in operator information that supported site closure. And while some moral hazard discussion in the literature emphasized the risk that the quality of storage locations would decline over time as CCS projects proliferates, this concern appears to be relevant only in the distant future, at which point the industry’s experience with subsurface movement of CO₂ could be expected to bring techniques to ameliorate any corresponding risk.

Select U.S. states have legislated that they will assume any liabilities at sites in their jurisdictions, albeit with different conditions, suggesting they have gotten comfortable with assuming such liability. Although the state actions represent progress, this patchwork of state legislation, as well as the associated administrative bodies and Trust funds, is suboptimal from a clarity and financial management perspective.

A federally sponsored program, in which the government assumes liability for geologically stored CO₂ during the LTS phase, is a workable answer. A national program can offer efficiency and consistency advantages relative to state-run models.

A national program must have three elements. First, it must stipulate that an entity assume responsibility for monitoring and management of the stored CO₂ sites. Second, a Trust must be funded to pay for ongoing monitoring expenses and any potential remediation costs should leakage result in damages. It has been suggested (and the state programs have stipulated) that such a Trust would be funded by a “tipping fee” levied on every ton of stored CO₂. Third, Congress must legislate the conditions in which the developer would, or would not, be released from liability.

As to the size of the tipping fee to be levied on stored CO₂, and therefore the size of the Trust, risk analysis that is required for Class VI well approval offers insight and suggests that tipping fees below $0.10 per stored ton of CO₂ can reasonably be expected to cover ongoing expenses and any potential remediation. This fee is in line with the demands of most of the states that have legislated liability relief. With that said, an expressed provision that the tipping fee is to be reviewed over time to ensure its adequacy makes sense.

As a final thought, specific to the role that the insurance industry can play in assisting with FA, this paper suggests that “bending” on both sides will likely be necessary. In other words, the insurance industry likely needs to deepen and accelerate a commitment to act, even in the absence of significant historical loss data, and project developers likely need to accept that shorter term coverage will be far easier for insurers to accept.

Introduction

There is consensus that Carbon Capture and Storage (CCS) is an integral activity in the effort to limit global warming and its harmful effects. That contribution requires a significant scaling of CCS operations. To name just one example, the International Energy Agency (IEA)’s most recent Net Zero scenario includes CCS removing one billion tons of CO₂ per year by 2030 and six billion tons by 2050, up from 45 million tons captured and stored in 2022.

Initiatives for new CCS projects are indeed proliferating. From the current 41 active projects globally as of 2023, there were another 26 under construction, another 121 in advanced development, and 204 in early development. If all these projects were to proceed, the 392 systems would have 360 million tons per annum of storage capacity.[1] In the U.S. alone, there are 14 active projects, eight under construction, 73 in advanced development and 59 in early development, for a total of 154 projects.

Yet this apparent momentum to pursue CCS projects may be at least somewhat misleading, particularly in the U.S. Perhaps most prominent among concerns is whether the projects can truly be considered “economic” or whether some additional support will ultimately be necessary[2]. Less explicitly perhaps, the interest suggested by permit applications may belie unease among developers regarding liability they may be subject to over the long lives of CCS projects. Such unease is likely particularly acute in the U.S., a function of the lack of certainty with respect to ownership of pore space, our country’s tort system and some history of companies being subject to retroactive penalties.

In this paper, risk factors, operational and financial, and their mitigation related to geological storage of CO₂ are considered. The topic is divided into the following sections:

1. Risks Related to Geological Storage and Operational Risk Mitigation. This section introduces and contextualizes the primary risks associated with geological storage of CO₂, namely leakage (from the designated storage area), induced seismicity, and, from a financing and insurance context, the relative lack of operating experience of many would-be project developers. It segments the discussion across the various phases of the storage lifecycle during which the developer continues to operate or have operations responsibilities at the storage location. In the process, the requirements that have been established by the Environmental Protection Agency (EPA) to obtain a permit to drill the (Underground Injection Control Class VI) well specified for this activity (i.e., permanent storage of CO₂) are explained.
2. Community Infrastructure Risk Mitigation. This section posits that the social implications of projects must be evaluated along with their feasibility to better understand the risks and to afford a more holistic approach to their mitigation. It notes that a large proportion of the proposed CCS storage projects in the U.S. (with submitted applications for Class VI wells) are in communities with limited supporting infrastructure, which can meaningfully influence a project’s construction success and ongoing monitoring and risk response capabilities.
3. Financial Risk Mitigation. This section complements the Operational Risk Mitigation section, delving into the various “financial” mechanisms project developers can employ to mitigate risk (again during the operating phases of the project lifecycle). It discusses the requirement by the EPA as part of the Class VI well application process that the developer demonstrate adequate Financial Assurance. And it discusses the current landscape and prospects of obtaining commercial insurance, which can help demonstrate financial assurance and/or protect the sources of revenue for the project (tax credits and potentially carbon credits).
4. Long Term Stewardship Risk Mitigation. After CO₂ injection and a prescribed period of continued monitoring (generally lasting decades) has ended, geological storage projects enter what is commonly referred to as their Long Term Stewardship (LTS) phase. This section considers the argument that after the obligations of the project developer have been fulfilled, the project developer should be able to “walk away” from the project and be absolved of any lingering liability/responsibility. Several U.S. states have approved legislation related to this, with varying degrees of liability relief and costs; the costs take the form of a per stored ton “Tipping Fee” to be borne by the developer to cover the states’ ongoing costs and potential liability. The section also considers the value of having a nation-wide version of such a liability transfer.
5. Conclusion/The Way Forward. This section reflects on takeaways from the preceding ones and offers suggestions for how developers, insurers and government can adapt their approaches to foster more geological storage development (it also highlights steps the insurance industry is taking to do just that). It acknowledges the challenges that new-to-the-world developers pose, in terms of capital raise and securing insurance, for example, and posits that further study, of the implications and to devise solutions, is warranted.

Risks and Operational Risk Mitigation

The use of Carbon Capture and Storage (CCS) as a climate mitigation tool envisions the permanent underground storage of CO₂. The prospects for large scale adoption of geological storage have raised concerns regarding the risks — of property damage, environmental degradation, and to human health— if stored CO₂ were to leak to the surface or into shallow water resources.

This concern under-appreciates the degree to which the industry and regulators can mitigate the risk of leakage or damages. Decades of scientific study of the subsurface are being applied to the subsurface assessment and approval of proposed storage sites. Monitoring techniques are applied before, during, and after injection to ensure that the CO₂ plume is developing and migrating as expected and remains contained within the injection interval. While physical ‘trapping’ of the CO₂ in the subsurface is the primary containment mechanism, post-injection pressure dissipation and other natural processes such as solubility trapping and CO₂ mineralization lessen the risk of leakage over time.

CCS is also often characterized as being unproven, which does not do justice to its history. As of last year, there were over 40 CCS projects with geological storage (including field tests) that had either completed injections or for which injections are ongoing. This operating history has been very supportive of the ability to select subsurface conditions that can contain injected CO₂.  Further, within the United States, operators have been injecting CO₂ into the subsurface for enhanced oil recovery (EOR) since the 1980s. While the goal of permanent storage is unique to CCS, the experience and learnings from EOR operations translates to CCS projects.

Although current regulations, which bring to bear this understanding of the subsurface, can go a long way to mitigating the risks of leakage, appropriate management of CCS projects during operations is also critical. This allows for a separate but related risk — the viability of the developer/operator. This “business” risk is exacerbated by the landscape of proposed developers (a new breed of which lack operating history), how they are raising funds, and their reliance on government subsidy (and presumably for many, carbon finance).

This section discusses the risks for third parties (i.e. not for the developers) associated with geological storage of CO₂. The risks are segmented across the various phases of the storage lifecycle — construction, injection, post-injection/site care (PISC), and Long-Term Stewardship (LTS). Each sub-section describes the engineering- and operational-related steps that are being taken by operators and regulators to mitigate such risks, i.e. related to site selection, well design, injection conditions, monitoring, and well closure.

THE LEAKAGE RISK PROFILE OVER TIME

Although this section addresses several risks, arguably the most pressing is the potential for stored CO₂ to migrate away from its designated area, as this presents potential for third party and environmental damage. It has been determined that the risk of leakage across geological storage sites peaks during the latter stages of the injection period as CO₂ volumes and pressures build.  The risk holds roughly steady until injection ends. When injection stops, pressures are expected to decrease over time with continued migration of the plume, solution trapping and (to a lesser degree) mineralization of the stored CO₂. Thus, the risk of leakage is expected to decline materially over the ensuing decades (see Exhibit 1).

Exhibit 1: Risk Profile Curve for CCS Sites

 

 

 

 

 

 

 

 

 

Source: Sally Benson, Stanford University, Global Climate & Energy Project (2007)

RISKS STEMMING FROM THE BUSINESS ENTITY (THE PROJECT DEVELOPER)

A CCS project developer earns revenues, in the form of tax credits and potentially carbon credits, during the injection period. Meanwhile, the developer incurs the costs associated with (capture/acquisition of the CO₂ and) injection, debt service, royalties to landowners, and, particularly for smaller developers, providing Financial Assurance to the EPA.

Currently, there is a diverse landscape of CCS project developers, with companies of varying sizes, focus/specialty, operational capacity, and history of successful project execution. This includes start-ups with no “other” assets, (i.e. its assets relate only to the proposed CCS activities) and limited operating experience up through oil supermajors and other large industrial behemoths with significant resources. Of the 113 EPA-tracked projects that are characterized as being capture, full chain, transport or storage, 35 can be considered as having developers that are “new” entities, i.e. companies (or consortia of companies) without meaningful operating history (in any activity, see Exhibit 2). All else equal, these CCS start-ups raise questions about financial viability as a developer/operator has responsibilities that last more than fifty years.

Exhibit 2: Categorizing U.S. Geological Storage Project Developers

 

 

 

 

 

 

 

 

 

Source: IEA (2024), CCUS Projects Database

To mitigate operational risk, permit applications submitted to the EPA or the states, require evidence of Financial Assurance (FA), which is designed to backstop safe site closure, proper plugging and abandoning of injection and monitoring wellbores, restoration of the site to its original state, and remediation of any environmental damages, for example in the event of leakage of stored CO₂. (FA is discussed in more detail in the Financial Risk Mitigation section.)

OPERATIONAL PHASES RISK REVIEW

Construction Phase

CCS projects are large scale, multi-faceted engineering & construction projects. For geologic storage, operators must construct a CO₂ injection well and subsurface monitoring wells. Well construction involves a series of carefully sequenced tasks, executed by teams with diverse expertise and utilizing specialized equipment, often provided by various companies/contractors. Throughout the construction phase, developers must navigate the risks of schedule delays, cost overruns, and accidents that could result in injuries or damage to equipment and property. These risks are exacerbated by project management complexity.

Yet these risks are consistent with those performed routinely in hundreds of active oil and gas well operations across the U.S. As such, the financial and insurance industries are adept/experienced at evaluating and “pricing” these risks into supporting insurance, lending and other products.

Injection Phase

During the injection period, there remains risk of equipment damage and bodily injury at the injection (well) site, although the risk of such incidents is lower than during construction as there are fewer people present on site and fewer crews coordinating activities.

Instead, greater risk (at least for third parties) relates to the CO₂ plume and its containment in the subsurface[3]. The first risk in this vein is that CO₂ migrates outside the anticipated containment area, laterally or vertically. Lateral migration could occur due to unanticipated reservoir heterogeneity, or insufficient capacity in the modelled plume area. Vertical migration is more problematic and could occur through the caprock along unmapped or reactivated faults, or along improperly plugged and abandoned wellbores. The potential damages that might occur or liability that might be incurred include:

• Property, the developer’s or that owned by third parties
• Environmental, for example if agricultural resources or drinking water is affected
• Trespass, if the CO₂ is determined to have migrated to an area to which a different owner owns the rights
• Forfeiture of the revenue or tax credits that were based on that “lost” CO₂

Concerns regarding CO₂ leakage stem in part from an experience at the In Salah project in Algeria in 2007 during which it stored CO₂ was known to have experience unanticipated lateral migration. Operations were suspended in 2007 and resumed in 2009.

The second risk is of (induced) seismicity during injection. In other words, there is risk that the injection of CO₂ creates seismic events that, if strong enough, could result in property damage (the developer’s or third parties’), bodily injury, or environmental liability. This concern stems largely from the experience in the U.S. with disposal wells, into which are injected large volumes of “wastewater” produced through hydraulic fracturing of oil and gas wells. Operations of such disposal wells has demonstrated that nearby fault lines can be re-activated, potentially leading to seismic events that can pose a threat to safety and property[4].

To minimize both risks, the project developer takes several steps, many of which are mandated by regulators.

Subsurface Evaluation

Subsurface evaluation is undertaken as part of the EPA’s Underground Injection Control (UIC) Class VI well program application process.  Injection location and depth are selected based on the suitability of the reservoir, the overlying seal/caprock, and the overall basin setting that will ensure permanent containment. Suitability is determined based on extensive data collection, analysis, and a final Geomodel that represents the closest approximation of subsurface conditions, including any faults or fractures within the Area of Review (AOR), and predicts the geometry of the CO₂ plume as well as any geochemical reactions that might occur upon injection.

Similarly, as it relates to hydrogeology, the vertical and lateral limits of all underground sources of drinking water (USDWs) and their positions relative to the injection zone(s) must be included. Baseline geochemical data on fluid- and solid-phase geochemistry of all USDWs, must detail pre-injection monitoring results (natural baseline geochemistry) as well as planned sampling/testing of geochemical analytes during and after injection. These shallow monitoring procedures are implemented to ensure that no environmental degradation occurs in the event of a CO₂ leak.

“Man-Made” Risks/Operational Controls

Class VI guidelines for a CO₂ injection well include elements that address the “man-made” risks — specifically concerns related to CO₂ handling and risk of leakage. To offer just two examples:

• The prescribed metallurgy of the casing is far more corrosion resistant (because CO₂ is more corrosive than hydrocarbons).
• When the injection well is plugged when injections are to be stopped, it is mandated that the entire annulus surrounding the wellbore be sealed with (corrosion-resistant) cement. This differs from oil & gas operations, for which only (hydrocarbon-bearing) sections of the subsurface must have a cement barrier applied.

During injection operations, the developer/operator monitors subsurface pressures to ensure that fracture gradient is not exceeded, and that the injection reservoir is able to handle the anticipated rates and volumes of CO₂[5]. Operators are also responsible for monitoring across the Area of Review (AOR), which includes not only the CO₂ plume, but also the pressure front (pressures increase outside the extent of the CO₂ plume as brine is displaced in the reservoir).

Post Injection/Site Care (PISC) Phase

At the end of the injection period, the developer plugs the injection well. As noted above, EPA Class VI regulations include taking additional steps to limit the risk of CO₂ leaking to the surface along the wellbore or annulus.  In the PISC phase, activity at the site is limited to monitoring for CO₂ leakage. Thus, operational risks that were present during the construction or injection phases become immaterial.

The duration of the PISC phase is variable and site specific. The EPA mandates 50 years, after which time operators are no longer required to maintain FA; as is discussed in the LTS section, U.S. states have set different time frames to release project developers from their obligations.

During the PISC phase, it is presumed that the principal risks are the potential for CO₂ leakage and, related, the operator’s ability to continue requisite monitoring activities. As is noted above, it is believed that the volumes of CO₂ that are at risk of leakage continue to decline through this period.

Long Term Stewardship Phase

Upon satisfactory performance of the stored CO₂ during the PISC phase, the site can be “closed.” Site closure marks the beginning of the Long-Term Stewardship (LTS). Functionally, operations during the LTS phase are limited to some periodic monitoring of the site for leakage; given the risk of leakage is expected to continue to decline over time, as discussed above, such monitoring can presumably be less frequent than during PISC.

Rather, defining an LTS phase sets the basis to consider the potential for the responsibilities related to monitoring — and to assuming any liability should it arise — to be held by a party other than the developer. In other words, it has been contemplated that the developer would hand off responsibility (and ownership) to a public or quasi-public entity after the PISC phase/site closure. This idea will be considered further in the Long-Term Stewardship section.

Preliminary Evaluation of Community-Oriented Risk Analysis

CCS projects are slated to be multi-billion-dollar infrastructure projects comprised of carbon dioxide pipelines, capture sites, and injection wells for the sub-surface. While the technical feasibility of carbon capture projects is explained systematically, for example as part of the permitting application for Class VI wells for geological storage, the social implications of projects are equally important and must also be evaluated to better understand risks and holistic mitigation of liability for all involved parties.

Integrating the social implications of a project begins with a determination of what communities will be impacted. The potential benefits and burdens, both directly and indirectly stemming from the project, can then be assessed, which can feed into the development of a social risk calculus for each impacted community.

It is important for project developers to recognize that these assessments work both ways. On the positive side, there is consideration of how these projects can positively impact the communities in which they are located and as well as benefit from community stakeholders participating in the long-term stewardship of the project. The assessment is also not merely a “one-time” application. Rather it would serve as a baseline for upcoming projects.

On the risk side, a more thorough understanding of what is often limited infrastructure — in the forms of on-site power, information for monitoring and maintenance, and road access to a site — can materially impact the relative success of the project’s construction, long-term monitoring, and risk response over the project’s lifespan.

This section provides an overview of research undertaken at the Colorado School of Mines regarding this social risk associated with geological storage in CCS projects. Publication of a more thorough review of such research is pending.

COMMUNITIES IN PLAY

As of December 2023, the Environmental Protection Agency had 61 Class VI Underground Injection Control permits under review, the current mechanism for projects to receive clearance for underground storage of captured carbon, excluding projects in Louisiana, North Dakota, and Wyoming, which have been granted primacy, or the right to authorize projects at the state level. Projects, especially those that require timetables of half a century or more of oversight, should have long-term considerations for the risks of the maintenance of a site’s infrastructure, especially in instances where sites are in remote areas that would solely be maintained by those liable for the site. Scenarios like these bring up contextual research questions:

1. How can communities be stewards of their lands and environment?
2. How are sites being evaluated for “ideal project characteristics”?
3. Are there limitations to isolated projects?
4. What community impacts are not being considered for these projects?

Additionally, considerations of the indirect impacts on communities by project development must be evaluated, and mitigation plans can be created with the communities to ensure that indirect burdens are not introduced to the communities, even before the construction of the well.

Methods

To determine the risk of long-term maintenance of injection sites and their respective infrastructure, an evaluation of the relative location of injection sites was compared against the infrastructure investments per county to understand what historic investment near sites has looked like. The Map of Progress from the White House was used as a publicly available dataset of private and public sector infrastructure investments based on regional data. The EPA has an active list of UIC Class VI Permits under review and the respective counties that the wells are in; however, the resolution of the data does not indicate exact locations, so evaluations such as the proximity of a site to a community are limited.

Findings

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 1. Breakdown of permit application counties without any reported infrastructure funding by EPA region

Discussion

A preliminary evaluation of injection site counties indicated that the current pools of projects on private and, at times, isolated lands are in counties with moderately low infrastructure funding, leaving the project owners responsible for road infrastructure. Without intentional oversight of the long-term management of the infrastructure associated with these projects, long-term access to the site may be compromised without consideration of the large timescales of over one hundred years of monitoring, the current time convention being used for evaluations of liability.

A clear example of pushback due to the limited consideration over community-based stewardship and collaborative evaluation of a project can be seen with the Navigator CO₂ pipeline in Illinois. On October 10^th, 2023, the 1300-mile Navigator pipeline project, which spanned over 30 ethanol plants based in Iowa, Minnesota, Nebraska, and South Dakota for sequestration in Illinois, withdrew its proposal to the state of Illinois, followed by the complete cancellation of the development ten days later after permit denial in South Dakota and a halting of the permit process in Iowa earlier that year. Navigator claimed in its press releases that the “unpredictable nature of the regulatory and government processes involved, particularly in South Dakota and Iowa.” ultimately led to the project’s cancelation.

Grassroots organizers argued that the systematic participation of communities in all five states led to the ultimate denial of the permitting for the pipeline. Publicized concerns around the project from these groups were centered on:

1. The use of eminent domain for carbon dioxide pipelines.
2. The limited liability of operators for damages caused by the pipelines and injection and long-term site stewardship.
3. A call to pause the project until the Pipeline and Hazardous Materials Administration released its revised safety standards for CO₂
4. Projects have limited benefits and extreme risks for the communities they pass through.

Key stakeholder groups in the area additionally stated:

“The cancellation of Navigator’s CO2 pipeline project highlights Navigator’s failure to adequately address the widespread concerns from farmers, landowners, environmental advocates, and elected officials from both sides of the aisle regarding basic protections for communities, land, and water resources. Navigator’s inability to secure enough public support for the pipeline sends a clear message that stronger protections are needed at both the state and federal level.” -Pam Richart, co-founder of the Coalition to Stop CO₂ Pipelines

“Get some safeguards in place on this entire technology — not only pipelines but how these gasses are captured and ultimately stored. The wisest thing to do seems to be to take a minute to figure out the risks and implications at all stages of the process… [and] make sure we don’t make long-term mistakes that jeopardize people in this short-term rush to cash in on these tax subsidies.”-Jack Darin, Director of the Illinois Sierra Club

CONCLUSION

The periods associated with the geological sequestration of carbon dioxide must be re-evaluated to consider the interfaces between a project site and surrounding communities. At any rate, no matter how isolated a project is, at some point, communities will be involved. Infrastructure projects of a timescale like that of carbon sequestration are limited and require intergenerational planning considerations to mitigate a project’s risks and liabilities. Isolated sites may serve as a mitigation strategy to prevent harm to communities and direct impact on the transport and storage process. However, it begs the question of what is sacrificed in exchange for the ease of process. Isolated projects fundamentally encounter fewer obstacles of social hesitation; however, they can lose the opportunity to incorporate communities as collaborative stewards to ensure project benefits can continue to flow locally and globally.

While injection sites may be isolated from communities, access to sites and the eventual establishment of the infrastructure needed for projects can indirectly impact communities in their proximity. Limited roadway access for heavy machinery at high volumes would require considerations for traffic flows for nearby communities, road impacts of the transportation process to the site, and the consideration of impacts for roadway closures, which can exacerbate the impact for communities with already limited access to major thoroughfares. Hidden impacts like these can equally disrupt the progression of projects and require careful consideration and collaboration with local communities to collectively benefit from projects and offer reduced liabilities for projects through shared stewardship of sites. Increased resolution of specific sites for injection could also allow for a dimension of analysis that considers the relative proximity of sites to population centers and evaluate the level of emergency response planning that would be necessary relative to its distance.

While community engagement is often considered a threat to the success of conventional infrastructure projects, CCUS projects of all scales can arguably only benefit from direct community engagement to collectively determine the risks posed by any single project and work to mitigate adverse impacts to communities in a way the serves the project’s completion and support for communities to be involved in site-specific stewardship, minimizing collective social resistance.

An evaluation of only one form of infrastructure in the development of CCUS projects is a limited view of the true nature of these systems.  Rather a series of additional steps could be used to understand better the risks that could be associated with remote sites by investigating the following parameters:

1. An analysis of the transmission corridors and their proximity to a site must be considered for the resiliency of the local grid to support these projects, should they be grid-tied.
2. An evaluation of the Emergency Response Infrastructure that would need to be tailored to address a catastrophic failure of a site.
3. An exploratory study for road compositions that could facilitate the construction phase of a well and remain substantially undisturbed over time.
4. Conducting a risk analysis profile that varies the degree of community engagement and collaborative stewardship of a project to reduce risk and singular liability of a project site.
5. Determining if sites are being unequally overburdened by the demands of the energy transition in the form of land use for energy generation, piping carbon dioxide through less-populated lands, etc.

Financial Risk Management

The U.S. government has implemented several policies designed to position CCS projects for growth. These include a regulatory framework and financial incentives such as 45Q tax credits and grants. Potential project developers are responding positively, as evidenced, for example, by Class VI well permit applications that have been discussed elsewhere in this paper.

Applicants and permit holders must, however, navigate potential liabilities that can manifest through the project lifecycle[6]. Federally approved projects must also meet rigorous financial assurance requirements that extend for at least 50 years after project completion to assure financial resources are available to respond to such liabilities should they emerge.

Thus, the US government policy actions designed to grow the CCS industry appear, in part, to butt heads with the federal environmental policies that seek to assure that any polluter remains strictly liable for damages caused, no matter how far in the future such latent liability may emerge. Unfortunately, no capital in the marketplace has a long-enough tenor to support many decades of such liability from any activity, let alone for projects with limited demonstrated implementation success at scale. So, the current government policies solve one financial barrier to scaling CCS projects, but not the other.

In this section, financial risk mitigation requirements and options are considered to address issues that cause bodily injury, property damage or other economic damage that might arise during geological storage projects. These do not obviate the need for any of the engineering or operational steps to minimize such risks. Rather, the financial mechanisms are enabled by such design and operational steps.

In the process of describing financial risk management options, the section considers the challenges faced by the commercial insurance industry to provide coverage for environmental liabilities of CCS projects and their developers. These challenges are exacerbated as some of the prospective project developers lack commercial/large project management experience and are looking to finance their CCS projects via project finance, i.e., without the benefit of a large balance sheet.

Note: this section addresses financial risk management during three of the four phases of the CCS lifecycle: construction, injection, and post injection/site care (PISC). Liabilities that might arise during the fourth and final phase, Long Term Stewardship (LTS) are addressed in a separate section.

REGULATORY REQUIREMENTS

Financial safeguards are mandated by the EPA’s UIC Class VI requirements for proof of adequate Financial Assurance (FA) measures; that is, project developers must demonstrate they have adequate financial resources to repair or compensate for certain damages. More specifically, the FA requirements are designed to assure adequate funding for safe closure of the facility; monitoring for leakage detection (including during a time-defined period that follows site closure); and remediation of potential liabilities if something goes wrong at the site that requires emergency response.

The applicable regulatory schema allows a permit applicant and permittee to satisfy minimum financial assurance requirements in several ways:

• Demonstrating Adequate Capitalization. Accomplished through maintaining sufficient cash reserves dedicated to these operations and providing evidence of assets, income streams, or other financial resources that can be drawn upon.
• Trust Fund. A dedicated financial mechanism to ensure sufficient funds are available. Operators are typically required to contribute a pre-determined amount based on quantity of CO₂ sequestered; this Trust can be funded over time, for example through a “tipping fee”[7].
• Surety Bonds. A contract between three parties: the project operator (principal), the 3^rd party entity issuing the bond (surety company), and the regulatory authority requiring the financial The surety company provides a bond to the operator, which guarantees that funds will be made available to the regulatory authority to cover potential long-term costs if the operator fails to fulfill its obligations related to the storage site.
• Letters of Credit. A binding commitment from a bank to pay a specified sum of money to a beneficiary (typically the regulatory authority overseeing the project) if the operator fails to fulfill their obligations related to the storage site.
• Insurance. A contract providing indemnity for named perils up to a limit of liability to the Named Insured, Additional Insureds and regulatory bodies (as specified beneficiaries) with specifically prescribed wording for this purpose.

CARBON CREDIT CLAWBACKS AND OTHER ECONOMIC DAMAGES

With FA successfully demonstrated as part of the permitting process, a developer may desire to also protect against other sources of potential loss. For example, it might seek to specifically protect its revenue streams in the event of CO₂ leakage outside of the designated zone (referred to as “reversal”).

At risk from a reversal of stored CO₂ is a “clawing back” of its Internal Revenue Service Section 45Q tax credits or other forms of credits that have been earned based on the permanent sequestering of the CO₂. Carbon credits, such as those sold through the voluntary carbon markets (VCM), are also underpinned by that stored CO₂[8]. Other economic damages can include “fouling” of the subsurface mineral rights of others or more generic sources such as suspension of operations / business interruption. Developers have financial risk management options for these reversal risks, including:

• Doing nothing. The developer remains fully exposed to the adverse event.
• Reserving a portion of the credits/benefits. The developer does not use all the tax or carbon credits it is eligible to receive or sell, respectively, and instead holds some in reserve. These reserved credits can be used to replace those “lost” through CO₂
• Creating a fund (e.g. through a Tipping Fee). The developer takes a portion of the revenues it is generating and puts it in a fund to be used in the event of CO₂
• Securing commercial insurance. This is discussed as part of the insurance section below.

THE COMMERCIAL INSURANCE INDUSTRY PERSPECTIVE

Some project developers would like commercial insurance to be a source of risk management assistance. And there are areas for which the insurance industry is already widely prepared to offer coverage. Common business risks — e.g., slips, trips & falls; property damage; errors and omissions, even pollution liability coverage and carbon credit loss — can be covered in today’s marketplace[9], beginning with the construction phase and continuing through PISC.

Additionally, over the past year insurance has emerged for underproduction / under-delivery of carbon credits (storing fewer credits than promised) or loss of carbon credits because of leakage. Firms including Kita and Oka are working towards making carbon credit insurance products available in the US. And there has been announcements of at least one policy placed in the U.S. to cover lost tax credits in the event of reversal. This suggests that insurance industry is progressing towards offering such policies (see Exhibit 1).

Regarding environmental liability, some project developers that have submitted applications for Class VI well permits to the EPA have received premium indications (not policies) as a form of pre-commitment. These are generally of the annually renewable Sudden and Accidental insurance policy type. The insurance policies are meant to be part of such developers’ Financial Assurance package as discussed above in the Regulatory Requirements section. This is encouraging, but until there is evidence of capital commitments, it cannot be said that commercial insurance is available (see Exhibit 1).

Exhibit 1: Insurability by Category and by CCS Project Phase

 

 

 

 

 

 

 

Source: The Payne Institute, Earth & Water Law Group

Why CCS Is Challenging For The Insurance Industry

The progress towards offering more insurance for CCS liabilities notwithstanding, CCS presents challenges for the insurance industry, for several reasons:

• Lack of historical experience with CCS projects. There is limited medium-to-long term proven performance of project success, and so limited actuarial data, for CCS in a wide variety of conditions; there are also — admittedly very few — examples in which CCS projects have had failures, including CO₂ leakage or injection rates falling short of anticipated levels (discussed more thoroughly in the Operating Risk Management section).
• Limited developer operating history. Insurers’ traditional decision-making about what and how to insure depends largely on the project developer’s history; this includes its technical, financial and management qualifications and experience with the project type. Insurance is far more likely to be made available to well financially qualified entities with sound operational history and demonstrated ability to run profitable businesses and / or projects. However, insuring project developers with limited or no business history, with a never-commercially-deployed technology is a challenge that makes risk management in all forms difficult.
• Subsidized business models. To make matters more challenging for underwriters, the business models for CCS rely on government tax breaks and/or carbon crediting for profitability. As such, should the subsidy disappear, so will the financial stability of the project operation, potentially leaving the project developer unable or unwilling to invest in proper engineering risk management promised in the permit applications and upon which the insurer relied during the underwriting process.

The Particular Problem of Duration

Further, the ask by developers for longer term policies is a particularly problematic, for several distinct reasons:

• Conflicting governmental policy. The CCS project dynamic itself creates conflict. It is driven by incentivizing government policy on the one hand (45Q tax credits) and government environmental policy on the other hand (Class VI well Financial Assurance requirements designed to protect human health and the environment). A stark example of this is that the EPA’s Financial Assurance regulations extend, by law, the duration of the project — from a liability perspective — 50 years beyond when it ends from an operating/business perspective.

While insurance can, and does, resolve such conflict in many public policy settings[10], it has come when the insurance industry has been a highly involved participant in that policy development. By contrast, insurers can be forgiven for thinking that CCS policy makers seem to expect insurance to manage a risk, again in which it has no history, with little engagement or concern about insurance’s overarching priority (to preserve capital).

Lack of availability of long-term capital. The ask for long-term policies flies in the face of an important constraint for insurers: raising money in the capital markets. Capital in the property and casualty insurance markets is not generally made available on a long-term basis (with few exceptions[11]). Thus, while it is true that insurers carry long term capital, so termed because its obligations are potentially spread out over decades, CCS lacks the history to permit the development of financial instruments necessary to hedge long term obligations related to CCS operations. Hence, long-term CCS policies leave the insurer with a significant risk of mis-pricing risk against CCS premiums.

• Risks of this sort are generally held by the operator. Insurers “see” projects in which the bulk of the activity (and therefore risk) relates to operations (i.e. the proper injection of and then continued storage of CO₂). This suggests to insurers that traditional operations policies are more appropriate — in which insurance is generally provided on an annual basis and for which operating history and ongoing risk management safeguards can be reviewed to support annual renewal and pricing — than long-duration policies.

The demand for these long-term policies appears to stem from regulatory requirements and not a natural business need for such a duration. The disconnect is compounded because some project developers — particularly those incorporating for this purpose — seek to terminate developer liability at the conclusion of the injection period. This is consistent with the use of Project Finance to support CCS projects including Special Purpose Vehicles (SPVs). Put differently, because they are dependent on the capital markets, these developers feel they need an exit path from the liability and desire longer term insurance policies to facilitate that project exit.

Putting all these challenges together, many insurers believe the industry is simply not in a position, without substantive public policy adjustments, from scope to regulation, to provide long term coverage.

It is worth noting that some of the emerging credit compensation and environmental insurance policies being considered for offer do have a 10-year duration. The caveats, however, are important. For now, these are being considered for non-U.S. projects only, and then only in jurisdictions where (1) the tort-based liability risk is deemed to be significantly different or simply non-existent as contrasted with the US and / or (2) where the sovereign has agreed to a liability cap or indemnity schema for the project developers. It remains to be seen how much capital insurers are willing to commit for these policies even in jurisdictions where liability is limited largely to property damage without tort liability.

The Competition for Underwriting Dollars

The final observation about the insurance landscape, which compounds the challenge, is the fact that CCS falls into a specialty underwriting area within the insurance industry called Commercial Excess and Surplus (E&S) lines insurance. Less than approximately 15% of the direct written premiums in the North American insurance marketplace are derived from all manner of specialty risks, including but not limited to railroad, hospitals, directors and officers, rep and warranty, professional liability, oil and gas, environment and more (see Exhibit 2).

Further, the Commercial E&S market has both limited risk capital allocations and very limited human resources (let alone human resources qualified to analyze CCS project risks). This creates the challenge for CCS that it must compete for capital with established, much better understood sectors such as automobile, property, and workers compensation. To find capacity for CCS in a constrained market, displacement of currently underwritten business must occur. However, such re-allocation would require training of underwriters and creation of all manner of analytic tools sufficient to meet the operational metrics and fiduciary duty of the insurers taking such risks. Given that many other industries have a long history, well developed analytics and loss history, existing knowledgeable human resources and use largely short term (3 year or less) policies, making that swap is a hard sell.

Exhibit 2: U.S. Insurer Property & Casualty Sector, % Direct Premiums Written by Segment, 2022

 

 

 

 

 

 

 

 

 

 

 

 

Source: Federal Insurance Office, U.S. Department of Treasury (data from S&P Global)

Long Term Stewardship: Releasing Residual Liability

In a carbon geological storage project, the final phase is referred to as Long Term Stewardship (LTS). It follows the Post Injection and Site Care (PISC) phase, i.e., after the injection well has been plugged, the developer has monitored the subsurface for any CO₂ leaks for the prescribed period, and the site has been “closed.”

By the LTS phase, the risks of leakage of CO₂ are believed to be significantly lower than during or just after injection (this is discussed more thoroughly in the Operational Risk Mitigation section). Yet, given that the CO₂ is supposed to remain stored for hundreds if not thousands of years, obligations remain. And in the very unlikely event of a CO₂ release, there needs to be a responsible party/body to handle remediation. With the project developer having been responsible for the CCS project for over fifty years, and with revenue streams associated with the project having ended decades earlier, it is reasonable to consider when the developer can “walk away” from the project. Said differently, it is plausible that developers would be deterred from engaging in CCS at all if their liability is indefinite[12].

Hence, a risk management framework that relieves the developer of liability during the LTS phase has been envisioned and, to varying degrees, enacted in eight U.S. states and in Europe. All such frameworks have as a prerequisite that the developer has performed its responsibilities throughout the preceding phases. In effect this means that the storage site will have behaved as expected for decades or else the operator will have remediated any operational shortcomings (leaks) to the satisfaction of regulators.

The frameworks also include that the developer will have funded a “Geological Storage Trust” (Trust) to be put toward the costs of ongoing monitoring as well as remediation and liability (if this is assumed by the jurisdiction’s government) if there is environmental damage. This Trust is to provide a significant layer of protection against government (or taxpayers’) exposure.

As opposed to the current patchwork of LTS solutions in the U.S., a nation-wide program can be considered. The benefits for developers of such a framework could include (1) broader geographic coverage; (2) more consistent and comprehensive assumption of liability; and (3) the presumed financial efficiency/risk diversification of having one larger Trust that can allow lower funding requirements vis-à-vis smaller ones.

The eight state risk management frameworks have coalesced around charging a “tipping fee” of $0.07-0.10 per ton of stored CO₂ to fund their respective Trusts. The rationale behind the funding requirements in state frameworks is not generally articulated. However, that tipping fee appears consistent with independent analysis of “residual” risks (i.e., those remaining at the LTS phase).

A sub-$0.10/ton tipping fee would generate substantial funds in the Trust for government use once it assumes responsibility. To illustrate, the 154 projects at some stage of development in the U.S. (which admittedly are unlikely to all become operational) have nameplate CO₂ storage capacity of 330 million tons per year. A $0.07/ton tipping fee would generate $23 Million per year, or nearly $700 Million over 30 years of injection operations and over $900 Million over 30 years assuming the tipping fees are invested and earn a 2% compound interest rate.

This section is organized as follows. First it describes key elements in a risk management framework, i.e. what needs to be included should government assume responsibility for management and liability of a geological storge site post site closure. It then considers the contention that such a transfer can create moral hazard for project developers. Next, it describes related individual state legislation, and then discusses adequate tipping fees. The section closes with a brief review of previous national risk management framework legislation that helps inform consideration of a CCS LTS model.

THE CONTOURS OF A NATIONAL LTS RISK MANAGEMENT FRAMEWORK

Any framework that is to assume the responsibilities and liabilities of CCS projects in the LTS phase must have three elements.

First, creation of an entity. This entity is to accept title to and responsibilities of the site during the LTS phase[13]. This entity would be liable in the event of damages claimed due to leakage from any of the storage sites in its holdings (unless resulting from something that is legislatively excluded as is described in point 3 below).

Second, creation of a Trust. This Trust is to fund the activities of the entity, including ongoing monitoring of leaks, remediating any damages and paying for any associated liability in the event of a leak. Academics and others have recommended that the Trust amount be flexible and responsive to the latest assessments of (leakage) risk for the projects; it was assumed that operating experience would help inform such estimates. Consideration was given to the idea that maximum levels would be determined on a project-by-project basis.

Third, delineation (by the legislature) of conditions for and the extent of liability assumption. Legislation would allow the transfer of long-term liability to the regulatory entity. The legislation is to include conditions for that transfer, including defining under what circumstances the CCS operator remains accountable for damages and remediation costs. Those circumstances could include, for example:

• cases of negligence
• provision of erroneous information to regulators
• violation of law during the operating periods

Legislation would also establish what happens if expenses to remediate damages from leakage exceed those pooled in the Trust. As is noted above, the Trust’s tipping fees collected across a significant number of storage projects would pool large sums, suggesting that any damages can likely be fully paid for out of the Trust. Having the developer remain responsible for costs in excess of the Trust’s funds would therefore help address concerns (which we argue are exaggerated) regarding Moral hazard at very little risk to the developer (see below for more on this topic). Yet it would compromise the liability relief that can be helpful to catalyzing more project development.

A national LTS framework has the potential to improve upon the state frameworks that have emerged to date. As is described in detail below, state action thus far has yielded an inconsistent patchwork. The states are assuming monitoring responsibilities, and most (but not all) have also taken on liability, albeit to varying degrees. A national framework, however, offers the potential to significantly expand geographic coverage relative to what has been enacted thus far and create a comprehensive solution on liability coverage.

Further, there is a presumed financial efficiency to having one Trust rather than several. The theory of Risk Mutualization states that when risks are all combined into one large pool, they become more stable and predictable due to the diversification effect. The impact of any single risk incident is reduced, and they tend to converge toward an expected value or average. Moreover, the operating and administrative costs of managing a single pool should be lower than the cost of managing several smaller pools (although one can envision local administration of responsibilities, including monitoring).

Notably, UK and EU CCS policy includes provisions for national-level liability assumption during the LTS phase of CCS projects, although the UK has not passed legislation (see Appendix II).

ADDRESSING MORAL HAZARD

Consideration of transferring liability raised concern regarding the moral hazard this can create for developers/operators. In other words, analysis of a LTS risk management framework included consideration that if a developer knows it will be relieved of liability at some point, it may do less to ensure it takes the steps through the operating phases of a CCS project to minimize the risks of leakage over the very long term.

Resolution of moral hazard concerns lies in making the requirements during the operating phases of a CCS project (which as noted last several decades) stringent enough to prevent any opportunity to “cut corners.” The set of requirements is intended to combine to form a “storage security pyramid” (see Exhibit 1). The components of this pyramid have been incorporated into the EPA’s Class VI well regulations (physical and financial). These regulations, as discussed in the Operations Risk Management and Financial Risk Management sections, include rigorous subsurface evaluation prior to approval, ongoing monitoring during and after injection, appropriate site closure practices, and financial assurance to fund site closure and remediation of environmental damage[14].

Exhibit 1: The “Storage Security Pyramid”

 

 

 

 

 

 

 

 

Source: Sally Benson, Stanford

U.S. STATE LEGISLATION TO DATE

Several U.S. states have taken it on themselves to assume CCS project responsibility and liability during the LTS phase. These states have also set up dedicated Trusts, funded by so-called “tipping fees” charged on a $/ton stored basis, to help manage and monitor the storage sites. Each state’s actions are described below and are summarized in Exhibit 2.

• Illinois: The legislation in Illinois is very narrow. It states that long-term liability can only be transferred to the state if the project is part of the FutureGen initiative; FutureGen aimed to demonstrate the feasibility of clean coal technology through CCS. However, with the termination of FutureGen in 2015, this legislation is now outdated. Recent legislation, passed in June 2024, does not include any provisions for transferring long-term liability to the state, but has set up a CO₂ Administrative Fund to help all CCS operators with post injection monitoring and management. It is funded by operators at $0.31/ton if they have a Project Labor Agreement, which covers all terms and conditions of employment on a specific project and includes provisions that establish the minimum wage and other benefits of the laborers and provisions that prevent them from engaging in strikes. Operators without a Project Labor Agreement are assessed a fee of $0.62/ton.
• Indiana: The state can take on liability 10 years after documentation of cessation of injection and project completion has been provided. It has also set up a Trust to help the government undertake long-term management and monitoring of the site using a tipping fee of $0.08/ton of CO₂
• Kansas: The state is not responsible for any liability. Its framework does include a CO₂ Injection Well and Underground Storage Trust, funded by the operators at $0.05/ton, to aid with long-term monitoring and post injection activities.
• Louisiana: Liability can be transferred over to the state 10 years after injection has ceased, but the extent of the liability is capped at the amount available in the state’s Geologic Storage Trust Fund. This Trust is funded by developers (amount not specified) and covers the state’s expenses to carry out long-term management and monitoring activities.
• Montana: The state will assume long-term liability of the stored CO₂ 30 years after injection operations have ceased, but this is a two-step process. First, the operator must obtain a certificate of completion by demonstrating no CO₂ leakage for 15 years. Then, after an additional 15-year period, the liability can be officially transferred to the state. The state has set up a geologic storage Trust, funded through tipping fees (the fee varies by project), to be used for carrying out the state’s responsibility to monitor and manage storage reservoirs. However, MT also requires the CCS operator to provide financial assurances to cover the anticipated monitoring costs for the storage site for at least 30 years after the transfer of liability to the state. The legislation notes that the state can enter into cooperative agreements with other government entities to regulate CCS projects that extend beyond MT’s regulatory authority.
• North Dakota: ND can assume liability from the developer/operator 10 years after cessation of injection but requires the operator to provide documentation of project completion and proof of well integrity. If the operator cannot demonstrate the CO₂ reservoir has mechanical integrity, the state can still assume ownership of the storage facility but not the liability. The state will charge operators a $0.07/ton tipping fee, for at least 10 years during injection, to fund a Storage Trust, which the state can then use for long-term management and monitoring of the sites.
• Texas Onshore: TX can assume full liability of the project immediately after injection has ceased. The state has also set up the Anthropogenic CO₂ Storage Trust Fund to help with the long-term management and monitoring of the site. The Trust Fund is to be funded by the operator at $0.1/ton of CO₂
• Wyoming: Long-term liability can be transferred to WY 20 years after injection has ceased. State liability, however, is capped at the balance of the geologic sequestration Trust set up by the state. This Trust is funded by the operators using a tipping fee of $0.07/ton; the Trust also covers the expenses of the management and monitoring of the site.

Exhibit 2: Summary of State Liability Assumption Legislation

State	Liability and When State Will Assume	Storage Fund	Storage Fund Tipping Fee ($/ metric ton)	CO2 Ownership	Pore Space[15]	Class VI Primacy*
IL	No provision for transfer of liability	Carbon Dioxide Storage Administrative Fund	Project Labor Agreement- $0.62 W/o PLA- $0.31		Granted to the owner of surface land	No
IN	Unlimited liability can be transferred to state 10 years after injection cessation and certificate		$0.08			No
KS	State not responsible for any liability	Carbon Dioxide Injection Well and Underground Storage Fund	$0.05			No
LA	Liability transferred to the state 10 years after injection cessation but capped at the state’s carbon dioxide geologic trust fund balance. Operator liable for remaining	Geologic Storage Trust Fund		Some cases state, some cases operator		Yes
MT	Unlimited liability can be transferred to state 30 years after injection has ceased and certificate	Geologic Storage Reservoir Program Account	Project-specific	Operator	Granted to the owner of the surface land	No
ND	Unlimited liability can be transferred to state 10 years after injection has ceased and certificate	Long term monitoring fund + fund for admin expenses	$0.07	Operator	Granted to the owner of the surface land	Yes
TX Onshore	Liability transferred to state after injection has ceased	Anthropogenic Carbon Dioxide Storage Trust Fund	$0.10	Operator		No
WY	Liability transferred to state 20 years after injection has ceased but is capped at balance of geologic sequestration special revenue account	Geologic Sequestration Special Revenue Account	$0.07	Operator	Granted to the owner of the surface land	Yes

Source: State Government reports

*Class VI Primacy: State’s authority granted by the EPA to issue Class VI well permits

DETERMINING THE TIPPING FEE

Each state’s rationale for their tipping fee is not clear to the authors of this paper. Yet a more general assessment of storage project risk during LTS appears to support the “consensus” choice of a sub-$0.10/ton tipping fee.

That conclusion is based on risk assessments undertaken to establish Financial Assurance (FA) requirements (see the Financial Risk Mitigation section for more on FA). Such assessments consider risks throughout the operating lifecycle of the storage project, i.e. the Injection and Post Injection Site Care (PISC) phases, identifying specific events that would result in leakage. The assessments then estimate probability of occurrence of each event and cost to remediate. A Monte Carlo simulation analysis then derives an expected value (i.e., cost) of remediating leakage at each project, as well as a distribution of probability and resulting cost outcomes.

Many of the risks that are assessed in this process would no longer be present during LTS (i.e., the risks related to leakage through “active” injection or monitoring wells), while some of the remaining risks are believed to be lower during LTS than they were during operations (for more on this see the Operational Risk Mitigation section). With these caveats, a review of such a FA assessment can prove instructive in considering LTS risk and Trust requirements.

As an illustration, the FA analysis for ADM’s Class VI permit application, Wells #5-7, can be considered. The analysis identified 13 risks, along with annual probability of occurrence (see Exhibit 3) and cost to remediate (see Exhibit 4)[16]. Through a Monte Carlo simulation (100,000 runs), the expected value on this risk-weighted basis over the operational phases for these wells was determined to be $5.5 Million, or $0.14/ton of expected stored CO₂. This per ton expected value happens to be consistent with other studies[17].

Exhibit 3: ADM CCS Wells 5-7, Estimated Probability of Risk Events

 

 

 

 

 

 

 

 

 

Source: EPA (Petrotek analysis)

Exhibit 4: ADM CCS Wells 5-7, Estimated Costs to Remediate Risk Events

 

 

 

 

 

 

 

 

 

Source: EPA (Petrotek analysis)

Yet, again, this reflects an expected value of cost through the operational phases and some of these sources of risk would be expected to no longer be relevant during LTS; most prominently, 44% of the probability-weighted annual cost (using the high-cost estimates) were the result of pipeline-related events (see Exhibit 5)[18].

Replicating the Monte Carlo analysis for the risks that are still present during the LTS phase, as well as considering how those risks will have declined given the decline in pressure in the storage area through the years following injection, is outside the scope of this paper. Nevertheless, this example appears to support that the expected value of remediating a risk event for this project during LTS phase is (well) below $0.10/ton. Therefore, it is supportive of the tipping fees stipulated by most of the state legislatures, even when such fees are also intended to fund ongoing monitoring.

Exhibit 5: ADM CCS Wells 5-7, Breakdown of Probability-Weighted Costs to Remediate Risk Events

 

 

 

 

 

 

 

 

 

 

 

Source: EPA (Petrotek analysis), Payne Institute

HISTORICAL MODELS & LEARNINGS

Risk management frameworks, in which the government assumes financial liability, have had a long history in the U.S. and frameworks for LTS risk management drew on lessons learned from past legislation. Several of these frameworks include some commonalities, including pooling funds into a Trust from participating operators/projects and use of a tipping fee to fund that Trust. Further, the frameworks include that the government will assume liabilities that exceed the funds in the Trust if necessary. Any one example of past legislation is imperfect, in terms of its fit and scalability to geological storage LTS, but portions are instructive. Lessons to be learned from past programs include (and see Appendix I for more detail on specific legislation):

• Avoiding moral hazard requires operators to have meaningful financial liability throughout periods in which they are operating facilities (Price Andersen Act).
• The interests of actors involved with permitting must be aligned with those responsible for managing long-term liabilities. Policies that are too lenient/forgiving, or in the CCS case are insufficiently stringent in terms of site selection or operations management, can lead to excessive liability/underfunded Trusts (National Flood Insurance Act).
• It is important to regularly review estimates of loss potential and probability of loss. This allows for updating of funding requirements (e.g., adjustment of tipping fees on active projects) to avoid under- (or over-) funding the Trust. In the same vein, funding requirements for the Trust cannot be allowed to end, or “sunset”, independently of the evaluation that the Trust is adequately funded (Oil Pollution Act).

Conclusion: The Way Forward

This paper has identified the operational, financial and business model risks through the lifecycle of a geological storage project. It then discussed steps that are being taken to mitigate each risk, as well as to ensure that adequate funds are available to pay for closure and for environmental damages should any occur. In addressing these risks, the authors averred that the regulatory landscape appears adequate to address them.

For developers looking to mitigate various business risks, the landscape is still evolving. As was discussed in detail in the Financial Risk Management section, commercial insurance policies covering environmental liability and revenue (credit) reversal risk are emerging. Obstacles remain, however. In part this is because developers appear to be seeking a tenor for policies that differs significantly from normal insurance industry practice. This is aggravating what was already somewhat challenging for insurers given (1) the relative youth of the CCS industry, which accordingly gives the insurance industry little historical/actuarial data to work with; (2) the human and financial capital constraints within the insurance industry; and (3) the relative inexperience — as in, the limited operating history of any sort, let alone in CCS — of approximately 30% of the developers themselves.

The implications for this last point are two-fold. First, newly formed entities are more challenging for insurers to support as operating competency in general is harder to establish. Second, these entities are often seeking to raise funding through Project Finance-type mechanisms; this type of financing is more dependent on an exit strategy, relative to ongoing operating companies, to satisfy investors that similarly do not fully understand geological storage.

The landscape for risk mitigation over the very long term is evolving as well. As discussed in the Long Term Stewardship section (the LTS section), environmental liability transfer from developers to government is premised on the view that that indefinite retention of liability is a deterrent. Actions taken at the state level in the U.S. have created a patchwork of rules that relieve developers’ liabilities to varying degrees and after differing periods following injection site closure.

The LTS section acknowledged the related concern about moral hazard, but argued that the many regulatory requirements, plus the imposition of some form of “tipping fee” on the stored CO₂ to create a Trust, obviates such concerns. The tipping fee creates a pool of funds for a public entity to use for ongoing monitoring and to address any damages associated with CO₂ leakage — the risk of which should have already declined from the injection period and should continue to decline over time.

This concluding section considers options to help reconcile these challenges, and so attract more capital, and spur more CCS project development. The recommendations distill to (1) flexibility on the part of developers, for example to work within the insurance industry’s constraints, and (2) that the (federal) government should be willing to assume liability, particularly for very long term environmental liability.

The discussion below is organized to first address potential action by project developers, then the insurance industry, and then government.

WHAT PROJECT DEVELOPERS CAN DO

Developers of geological CO₂ storage have various options to handle the financial risks associated with their projects. As prescribed by either the EPA or states with the authority to approve Class VI-based projects (i.e., have been awarded primacy), developers must establish adequate Financial Assurance (FA) to ensure that sites can be closed and any environmental damage remediated; this FA can be established in various ways, as was discussed in the Financial Risk Management section. As is also discussed in that same section, a developer also has options to mitigate the revenue (tax or carbon credits) reversal risk to the storage project business model.

To the extent a developer seeks to secure commercial insurance for FA or for revenue credits, then it is incumbent on the developer to work actively with insurers — and to start such engagement earlier in the project development cycle than is typical with infrastructure development projects — to allay insurer concerns.

Further, it appears likely that developers will have to settle for shorter insurance periods. The authors’ communications with insurance industry representatives have made it clear that policies with a tenor beyond three years are meaningfully more difficult for insurance issuers (or that longer tenors must be offset by lower capital commitments). That would suggest that developers must accommodate to a model in which they assume the additional risk, including price risk, of having to renew insurance policies throughout the life of the project.

With respect to the impact(s) in the capital markets of having newly formed companies drive project development, further study is warranted. Such study could assess investor conditions and risk tolerance, for example, and thus bring more context to the questions of how much, or what form of, risk mitigation is required.

WHAT THE INSURANCE INDUSTRY CAN DO

The insurance industry is working to figure out how it can accommodate the requests to help support new climate technologies, including CCS. As noted in the Financial Risk Management section, policies are being introduced by brokers and “provisional” contracts to FA requirements have been placed, but it is as yet unclear how much insurer (and reinsurer) capital is available to support such contracts.

A different sort of example is the ongoing work being done by the Geneva Association (GA), an international body comprised of insurers and reinsurers. The body recently provided project developers (and the insurers themselves) with a framework to evaluate specific insurance options. This Insurance Readiness Framework addresses the risks across dozens of parameters in seven categories: Technology, Project & Organization, Legal & Financial, Physical (Climate), Business Interruption & Supply Chain, Long Term, and ESG.

At a recent GA-hosted symposium, members considered the need to educate actors across the ecosystem (but presumably especially project developers) how “to speak” to insurers, i.e. how (and when) to provide insurers with information that allows the insurers to perform due diligence and offer coverage. And the body encouraged its insurer members to collaborate to assist in providing coverage for climate tech innovation, including CCS; one benefit of such collaboration is to help offset the insufficient engineering talent across these insurers, which makes it more challenging for them to perform adequate risk engineering.

Beyond working with developers to manage the new product/technology risks, the insurance industry can participate in raising additional capital, to lessen the constraints in specialty-dedicated financial and intellectual capital described in the Financial Risk Management section. One such approach may be to foster development of alternative sources of capital, including Insurance Linked Securities (ILS)[19], that is tied to or includes CCS. ILS issuance emerged in the mid-1990s and has been used primarily by insurers to raise funds to support coverage of natural disasters. ILS buyers have included pension funds, sovereign wealth funds, multi-asset investment firms and funds, endowments, and family offices[20]. Notably, corporates have also issued ILS directly, raising the prospect of a different form of capital markets’ support for CCS projects. The insurance industry, given its ties with alternative capital buyers, can assist in both considering the contours of ILS and facilitating development of initial products.

HOW GOVERNMENT CAN HELP

The public sector has and continues to provide support to project developers to spur more investment in CCS. The largest program, in terms of breadth and of projects and intended dollar size, is the tax credit offered under section 45Q of the U.S. Internal Revenue Code. More targeted federal government programs include CarbonSAFE, which is seeking to foster storage sites for 50+ million tons of CO₂ from industrial sources, and the Department of Energy’s Carbon Dioxide Removal Purchase Pilot Prize, which is offering CO₂ removal credit purchase agreements worth up to $35 million.

Yet, as discussed in this series, the never-ending retention of liability for developers points to a conflict in policy relative to these supportive measures. Enacting provisions for the federal government to assume such liability post site closure, i.e., for the LTS phase, would be more consistent from a policy perspective — and this paper argues it can be done in a way that does not compromise the government’s commitment to responsible environmental stewardship.

Within any such arrangement for LTS, the amount of “tariff” or “tipping fee” to fund government’s LTS management Trust can also be considered. As addressed more fully in the LTS section, several states’ tipping fees of $0.7-$0.10 do not seem unreasonable given assessments of worst case environmental damages and the benefits of spreading the risk across a portfolio. That said, it is important that any LTS phase structure include provisions to regularly review operating experience across the global CCS industry regularly to help inform if the tipping fees are set correctly, i.e. to not under- or over-fund such a Trust.

Further evaluation of how government might help private actors and the insurance industry address liability coverage, including during operating phases, for CCS projects is warranted. Such consideration could take several forms. Presumably forms of support could include the government being willing to assume “first losses” under certain circumstances and/or losses above a certain limit, including what is available in Funds collected by tipping fees[21], [22] In this way (i.e., creating a tiered liability structure), government could engage in a form of public/private partnership with the insurance industry. As with any form of government assumption of liability, established practice must be deployed to ward against creating moral hazard conditions, as well as to limit the overall amount of government support to what is deemed necessary to catalyze projects.

CONCLUSION

This paper has sought to contextualize the risks in geological storage and to highlight that engineering and financial management practices in place today can substantially mitigate those risks. The degree to which liability “sticking points,” such as securing environmental liability insurance or relieving liability decades after project site closure, will dampen the pursuit of CCS projects is difficult to calibrate. However, to the extent liability is an overhang for projects, the mechanisms exist to provide relief in a way that does not let developers off the hook. Implementing these mechanisms can also send strong messages — to those opposed to CCS and sources of capital alike — regarding government and industry confidence in CCS storage integrity and the important role it must play in meeting carbon reduction targets.

Appendix I – Historical Risk Management Frameworks and Lessons for CCS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Appendix II – LTS Solution Considerations in UK And EU

Long term stewardship consideration in the UK has been contemplated for over a decade, with groundwork laid through the Storage of Carbon Dioxide Regulations 2010 and 2011 laws. During the active injection phase, CO₂ liability lies with the project operator who holds the storage license and permit. Operator responsibilities include monitoring, reporting, corrective measures, and obligations relating to purchasing allowances in case of leakages. The operator is also responsible for sealing the storage site and removing injection facilities.

Regulations require this liability to eventually transfer to the state after site closure. That said, there is no current law that specifically addresses the liability transfer process. The Energy Act 2023 lays the groundwork for CCS storage networks but does not address long-term liability transfer.

UK regulation does include provisions that allow the state/entity to recover costs from the operator in case of some negligence or if there is a leakage after the site is transferred. The Storage of Carbon Dioxide Regulations state that the transfer of liabilities (including leakage liability) will not take place at least 20 years after the operations conclude.

In Europe, the EU CCS Directive has established a legal framework for the responsible development and operation of CCS projects, including governing the long-term liability transfer from operator to the government, which is mandatory. The Directive requires that after a storage site has been closed in accordance with the terms of its operating permit, a minimum period of years determined by each member state must elapse before the transfer of liability can take place. Generally, this period must be at least 20 years, unless the operator convinces the state otherwise. After the transfer of liability, this member state is responsible for all long-term monitoring and corrective measures of the project site.

Endnotes

[1] This volume is almost certainly too low as there are numerous projects under development that are being tracked in this Global CCS Institute list that do not provide a capacity estimate.

[2] For example, by extending the 45Q tax credit beyond the current 12 years.

[3] This section ignores the business risk to the developer that it cannot inject as much CO₂ as intended. This risk, which for example is playing out currently in Chevron’s Gorgon CCS project, impacts the developer’s ability to earn revenues on the project.

[4] It is worth noting that there is other historical experience with induced seismicity. In one example, the Gallen deep geothermal project in Switzerland was terminated in 2013 due to a magnitude 3.5 seismic event. The event was attributed to deep drilling in fault-controlled regions, which exacerbated dormant faults. Additionally, an unexpected gas reservoir was encountered which posed challenges to well stability and safety

[5] Experience with wastewater disposal wells has shown that effective management of the rate and pressure of injection can mitigate against the risk of earthquakes associated with wastewater disposal wells.

[6] These risks take different forms, including but not limited to the physical risks of leakage of CO₂ or induced seismicity that could result in damages to property, bodily injury, and/or to the reversal of project revenues earned through tax or carbon credits. The Operational Risk Management section reviews the various risks associated with geological storage of CO₂ and the “physical”, i.e. engineering and operational, steps that can and are being taken to mitigate those risks.

[7] An advantage of establishing a tipping fee is that it sets aside funds that can be transferred to a governing body for risk management if the developer is to be released from liability at some point in the future. This transfer of liability is discussed in detail in the LTS section.

[8] Buyers of carbon credits in the VCM use them to report climate action beyond their own, internal efforts to reduce their carbon footprint

[9] It is worth noting that the purpose of traditional insurance is to indemnify the insured from fortuitous risks – e.g. the unexpected and unintended loss or damage; but insurance does not broadly provide indemnity for merely unwanted loss or damage.

[10] One example is regulation of worker safety and the use of workers compensation coverage and regulation of driving and other modes of transportation

[11] Today, the only long term funds in the capital marketplace are those securitized by government enabled structures and / or government funds such as those used to create the mortgage marketplace – and to a limited extent, some capital made available in the life insurance marketplace – but life insurance is supported by statistically robust expected life tables – a data source not available to CCS projects now or anytime in the next 50+ years.

[12] One might imagine that this is true for various types of developers. For established, publicly traded companies with plans for multiple (perhaps network/hub) developments, the build-up of potential liability over time could potentially rise to a level of materiality in investor opinion. For new-to-the-world entities that are particularly dependent on project financing, having an eventual exit, including liability release, may be critical to obtain such financing.

[13] Mindful of the moral hazard that such a liability “handoff” can create for other government actors, it was envisioned that this entity could be involved with the project as early as possible to give them stakes and more incentive to minimize risks. In other words, the entity could take on the role currently performed by the Environmental Protection Agency (EPA) or the state agencies (where states have been given primacy), including overseeing design and management, approving siting, mediating operational/permitting disputes, certifying certain completion milestones, etc. The entity would retain such oversight responsibilities through injection/operations and post site closure. With that said, the frameworks legislated by the states have not included that such entities be involved with CCS projects until the handoff at the end of the PISC phase.

[14] Analysis of moral hazard in CCS included the supposition that if CCS were to scale enough to be a meaningful contributor to atmospheric CO2 reduction it would involve trade-offs in terms of site selection. In other words, eventually, the U.S. would consider sites for geological storage that were less good than those chosen in earlier projects.

[15] Pore space ownership is decided at the state level and has not been established clearly for all U.S. states. Most states recognize the surface owner as the owner of the pore space, however.

[16] Where cost data/estimates were believed to be unreliable because of lack of occurrence historically, a 100x multiplier was assumed between the low and high cost estimates for conservatism.

[17] An example of another such study is the FutureGen 1.0 CCS project in Jewett, TX., performed by Industrial Economics in 2012, which yielded an expected value of $0.15/ton.

[18] Also noteworthy is that a further 32% of risk-weighted annual cost is derived from allowanced for undocumented wells in the area, a function of legacy oil & gas activity. This risk would not be expected to be present in this form across projects generally.

[19] Per a McKinsey report on the topic, “[a]lthough alternative reinsurance capital grew to account for 15 percent of the total reinsurance capital allocation in 2021 — up from 6 percent in 2011 — it remains a largely untapped pool of capital, with alternative reinsurance capital representing less than 1 percent of the global alternative assets under management (AUM)”

[20] It should be noted that the ILS market has underperformed other securities markets over the last few years as the increased frequency and severity of natural catastrophes resulted in losses for investors.

[21] Subject to the restrictions imposed by the U.S. Anti-Deficiency Act, see 31 U.S.C. § 1341 see https://www.law.cornell.edu/uscode/text/31/1341 or https://www.gao.gov/legal/appropriations-law/resources or https://uscode.house.gov/view.xhtml?path=/prelim@title31/subtitle2/chapter13/subchapter3&edition=prelim

[22] Whereas the LTS section specifically considers tipping fees to fund governments’ long term management Trusts, a tipping fee is also an EPA-accepted means to satisfy FA requirements during operating phases.

ABOUT THE AUTHORS

Brad Handler
Payne Institute Program Manager, Sustainable Finance Lab, and Researcher

Brad Handler is a researcher and heads the Payne Institute’s Sustainable Finance Lab. He is also the Principal and Founder of Energy Transition Research LLC. He has recently had articles published in the Financial Times, Washington Post, Nasdaq.com, Petroleum Economist, Transition Economist, WorldOil, POWER Magazine, The Conversation and The Hill. Brad is a former Wall Street Equity Research Analyst with 20 years’ experience covering the Oilfield Services & Drilling (OFS) sector at firms including Jefferies and Credit Suisse. He has an M.B.A from the Kellogg School of Management at Northwestern University and a B.A. in Economics from Johns Hopkins University.

Anna Littlefield
Payne Institute CCUS Program Manager and Research Associate
PhD Student, Geology and Geological Engineering, Colorado School of Mines

Anna Littlefield is the Program Manager for Carbon Capture Utilization and Sequestration for the Payne Institute at the Colorado School of Mines. As a current PhD student in the Mines geology department, her research focuses on the geochemical impacts of injecting CO2 into the subsurface as well as the overlap of geotechnical considerations with policymaking. Anna joins the Payne Institute with 8 years’ experience in the oil and gas industry, where she worked development, appraisal, exploration, new ventures, and carbon sequestration projects. Her academic background is in hydrogeology with an M.S. in geology from Texas A&M University, and a B.S. in geology from Appalachian State University. Anna is passionate about addressing both the societal and technical challenges of the energy transition and applying her experience to advance this effort.

Lindene Patton
Partner at Earth and Water Law, L.L.C., an adjunct professor at the George Washington University School of Law

Lindene Patton is a partner at Earth and Water Law, L.L.C., an adjunct professor at the George Washington University School of Law; and a real estate agent licensed in Virginia and Maryland. She is a transactional attorney with extensive experience in the business of insurance, InsurTech, environment and data technology, including IP, privacy and related compliance matters. She is a globally recognized expert in risk management, data, resilience and related risk management solutions, insurance policy and other financial services product development, including insurance supporting energy transition technologies like CCS.

Before joining E&W Law, LLC she served as Global Head of Hazard Products for Corelogic; Chief Climate Product Officer for Zurich Insurance Group, and division general counsel for a large global insurer, as well as associate general counsel for engineering and landfill design companies.

Nicolas G. Perticari Pesci
PhD Student, Civil and Environmental Engineering, Colorado School of Mines

Nicolas Pesci is a student in the Civil and Environmental Engineering Department. He is working on a PhD in Environmental Engineering and Science after completing an M.S. in Advanced Energy Systems and a graduate certificate in Humanitarian Engineering and Science from the Colorado School of Mines. His research is centered on the socio-technical implications of the energy transition, just outcomes, and community stakeholders’ involvement in the development process.

Felix Ayaburi
PhD Student, Operations Research with Engineering, Colorado School of Mines

Felix Ayaburi is a Ph.D. Student in Operations Research with Engineering at the Colorado School of Mines. He holds an MS in Mineral and Energy Economics from the same institution. His research interests include the application of optimization methods in underground mine planning, electric vehicle deployment and responsible sourced gas.

Siddhant Kulkarni
MS Student, Mineral and Energy Economics, Colorado School of Mines

Siddhant is a student researcher at The Payne Institute at Colorado School of Mines.  Currently pursuing his M.S in Mineral and Energy Economics, his research focuses on the commercial and insurance side of CCS projects and their risk management, as well as government incentive programs and schemes promoting the use of renewable energy. Additionally, he holds a B.S Honors in Economics from Symbiosis School of Economics, Pune. He is dedicated to advancing energy transition to renewables while addressing the various societal challenges that may come with it.

Darshil Shah
Consultant, Rystad Energy

Darshil Shah joined Rystad Energy in 2024 as a consultant, specializing in corporate strategy, financial and economic analysis in the oil & gas sector, energy policy, and clean technologies. Before joining Rystad, he focused on topics such as carbon markets, CCUS, and mining policy during his research assistantship at the Payne Institute while completing his Master’s in Mineral & Energy Economics at the Colorado School of Mines (Dec ’23). Darshil has gained valuable experience through roles at Enverus, where he honed his skills in private equity and energy markets, and at the American Petroleum Institute (API), where he engaged in energy-related economic and regulatory analysis. His areas of interest include economic modelling, carbon markets, CCUS, and energy market trends.

ABOUT THE PAYNE INSTITUTE

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DISCLAIMER: The opinions, beliefs, and viewpoints expressed in this article are solely those of the author and do not reflect the opinions, beliefs, viewpoints, or official policies of the Payne Institute or the Colorado School of Mines.