CCS projects hit delays, legal gaps, and insurance hurdles

The economic viability of CCS-dependent projects like Air Products' blue hydrogen facility is inextricably tied to the 45Q tax credit, which acts as a financial lifeline amid prohibitively high production costs. Initially projected at $4.5 billion in 2021, the project's cost estimate ballooned to $7 billion by 2023, underscoring how even generous subsidies and cheap natural gas prices could not offset escalating expenses. Without 45Q, such ventures simply cannot proceed, revealing the subsidy’s critical role in sustaining the U.S. blue hydrogen and ammonia markets.

Beyond production-side subsidies, the pathway to financing CCS projects now demands firm long-term offtake contracts and robust demand-side incentives to mitigate market uncertainties. Mechanisms like Japan’s contracts for difference and the EU’s carbon border adjustment mechanism exemplify how policy frameworks are evolving to guarantee demand for low-carbon products, which in turn reassures investors. This multifaceted support structure has become essential as companies like Air Products retreat from projects such as the Louisiana Clean Energy Complex, highlighting how fluctuating policy support and uncertain market demand continue to imperil CCS deployment.

Despite the European Union's ambitious target to develop 50 million tonnes per year of geological CO2 storage capacity by 2030 as a cornerstone for achieving climate neutrality by 2050, a significant 'bankability gap' persists due to legal uncertainties embedded within both EU-wide and national regulatory frameworks. This fragmentation creates structural barriers that deter private investment and complicate the financing of commercially viable CCS and CCU projects, underscoring the urgent need for harmonized legal clarity and designated oversight to unlock the sector's full potential.

By mid-2026, companies claiming the 45Q tax credit grapple with significant administrative delays and high rejection rates largely stemming from complex lifecycle analysis (LCA) pre-approval requirements. Since the pre-approval mandate took effect in 2021, the IRS had received 99 LCA requests by January 2026, including 54 originals and 45 resubmissions, underscoring procedural bottlenecks. The necessity for direct data through the end of the tax year combined with timing challenges in LCA approvals not only delays credit claims but also prevents taxpayers from utilizing the credit’s transferability feature on original returns, forcing amended filings and complicating financial planning.

These administrative hurdles have tangible financial repercussions: stakeholders report that prolonged pre-approval waits compel taxpayers and investors to continue funding carbon capture projects without timely credit recognition, thereby dampening investor confidence and slowing project execution. The absence of clear benchmarks and a designated lead agency to oversee the 45Q credit’s effectiveness further clouds the credit’s reliability, as Congress lacks structured data to evaluate its environmental and economic impact. This regulatory ambiguity exacerbates uncertainty for developers and financiers alike.

In response, the Government Accountability Office (GAO) has issued multiple recommendations aimed at streamlining the LCA approval process and clarifying acceptable datasets for calculating displaced carbon, proposing measures such as allowing taxpayers to rectify submission issues before outright rejection and developing GREET models to enable concurrent LCA submissions with tax returns. However, despite these well-founded suggestions, both the IRS and DOE have largely rejected five out of six GAO proposals, perpetuating existing procedural complexities and compliance risks that continue to hinder efficient tax credit claims and project financing.

By mid-2026, execution speed has emerged as a decisive competitive edge in carbon capture projects, transcending the traditional focus on capture technology alone. The setbacks experienced by ExxonMobil’s Baytown complex underscore how critical timely project financing, permitting, and delivery are, especially when coupled with securing durable commercial contracts and navigating evolving policy landscapes. This shift highlights that risk management through rapid execution and contract certainty is now as vital as technological innovation in ensuring project success.

Investor confidence in carbon capture initiatives increasingly hinges on the ability to sustain eligibility for federal incentives like the 45Q tax credit throughout lengthy, multi-year development phases. As regulatory frameworks continue to evolve, investment committees prioritize not just current qualification but the durability of that status across permitting, procurement, and construction cycles. This dynamic elevates the importance of policy stability and contractual commitments as foundational pillars that underpin financing decisions and project viability.

The intricate interdependence among public funding, customer contracts, financing, and regulatory certainty means that any weakening in one area can derail even technically sound carbon capture projects. This interconnected ecosystem demands a holistic approach to risk mitigation, where maintaining momentum requires synchronized strength across all fronts. Consequently, execution speed and robust contractual frameworks have become essential tools for managing these multifaceted risks in a rapidly shifting policy and market environment.

By mid-2026, insurance providers had emerged as pivotal gatekeepers in the carbon capture and storage (CCS) landscape, demanding risk assessments that far exceed regulatory baselines to address their unique financial exposure concerns. Unlike regulators, insurers focus intensely on the potential for CO₂ leakage during the 15-year monitoring period, which could trigger costly 45Q tax credit recapture, thus threatening the financial viability of CCS projects. This heightened scrutiny compels operators to provide exhaustive documentation on legacy wells—detailing drilling dates, plugging standards, and abandonment quality—and often mandates remediation efforts to mitigate leakage risks, reflecting a more conservative stance than existing regulatory frameworks.

Insurance companies require granular, quantitative risk evaluations that delve into detailed scenario planning and leakage quantification, asking critical questions such as whether potential leakage would be measured in kilograms or tonnes per day, and how long such leakage might persist before detection. These rigorous analyses are essential not only for accurately pricing risk and setting policy limits but also for reassuring institutional investors who are increasingly wary of financial liabilities tied to CCS projects. Given the prospect of repaying tens or hundreds of millions in 45Q tax credits due to leakage, securing insurance coverage against recapture risk has become a non-negotiable prerequisite for attracting infrastructure funds and other low-risk capital sources.

California's Elk Hills carbon storage project exemplifies the regulatory ambiguity plaguing early carbon capture deployments, as the state has yet to finalize its own carbon storage rules more than 19 months after the January 2025 deadline. This regulatory void leaves oversight fragmented among the California Air Resources Board, CalGEM, and the U.S. EPA, with no clear coordination or accountability framework, complicating enforcement and safety assurances.

The presence of hundreds of aging and potentially leaking wells near the Elk Hills injection site intensifies environmental and liability concerns, as it remains unclear which agency bears responsibility if carbon escapes. While CalGEM regulates these older wells, emergency protocols require notifying the EPA, highlighting a fractured oversight system that leaves monitoring and remediation duties unresolved and environmental groups alarmed about the absence of enforceable safeguards.

Without state-specific carbon storage regulations, California lacks the authority to impose stricter standards than federal mandates, limiting its ability to ensure that companies like California Resources Corporation (CRC) effectively contain injected carbon. This regulatory gap not only raises the risk of carbon leakage and environmental harm but also undermines public confidence, especially given the Elk Hills project’s potential to generate up to $3.2 billion in its first phase and as much as $30 billion statewide through federal tax credits and Low Carbon Fuel Standard incentives.