Short- and medium-term impact on the Gulf 

Qatar provides the clearest near-term example. The 4.1 Mtpa capture project at Ras Laffan was positioned as a cornerstone of Qatar’s lower-carbon liquefied natural gas (LNG) strategy and an anchor for scaling to more than 10 Mtpa by 2030. In November 2025, prior to the current escalation, QatarEnergy awarded an engineering, procurement and construction (EPC) contract to Samsung C&T valued at about $1.4 billion. The project had a relatively low-risk profile, with sovereign backing, integrated gas infrastructure, and alignment with Qatar’s LNG expansion. 

However, the current geopolitical situation introduces a new layer of risk. Since operations at Ras Laffan have been interrupted due to facility damage, the implications for CCUS are direct. If LNG throughput is curtailed by damage or security disruptions, the CO₂ stream feeding the capture plant disappears. Construction and commissioning timelines can slip, and restart sequencing is likely to prioritize safety and LNG revenue over carbon optimization. Even if storage remains technically viable, an integrated LNG-linked system means CCUS output can collapse during prolonged curtailment. 

More broadly, much of the Middle East’s planned capacity is tied to Qatar’s LNG-linked expansion, Saudi Arabia’s CCS hub strategy and the UAE’s Abu Dhabi-centered plans. The region’s growth narrative has relied on scale and project concentration, but higher geopolitical risk is reshaping execution expectations for the 2030s. As a result, around 20 Mtpa of capacity by 2030 across Qatar, Saudi Arabia and the UAE now appears unlikely; we see a downside closer to 12 Mtpa. Even projects already under construction may face commissioning delays as governments and national oil companies prioritize energy security and restoring processing capacity, with final investment decisions at risk of deferral. 

War-driven cost pressures on global CCUS 

Although the disruption is centered in the Middle East, its medium- to long-term impacts could be global. A prolonged closure of the Strait of Hormuz would likely raise energy prices, strain supply chains, and inflate equipment costs, increasing CCUS project costs both regionally and worldwide. Higher energy prices would lift operating costs for energy-intensive capture systems, while inflation would push up equipment and EPC expenses. Contractors may prioritize higher-margin oil and gas projects, tightening supply for CCUS and driving up installed capex. Greater uncertainty could also increase the cost of capital. Combined with potential reductions in system availability, these factors would significantly raise levelized costs, as fixed capital must be recovered over lower volumes of captured and stored CO₂. 

To assess global impacts, we conducted a sensitivity analysis of cost inflation in European CCUS, focusing on capture and transport. Despite available North Sea storage capacity, high costs and uncertain business cases constrain many emitters, while Europe’s still immature CO₂ transport network, particularly cross-border links, adds further risk. Near-term effects are therefore likely to concentrate among late-moving emitters and in transport, where higher material costs can delay final investment decisions and extend project timelines. 

Using a waste incineration facility as an example, the base levelized cost of CO₂ capture and transport (LCOC&T) is about $95 per tonne, above an EU ETS reference level of around $86 per tonne, implying a continued need for subsidies and policy support, as illustrated by the Stockholm Exergi BECCS project. Under a ‘middle impact’ case, where energy prices rise about 50%, capture and transport costs increase around 30% to roughly $124 per tonne versus the base case. Under a ‘severe impact’ case, with about 65% to 75% energy price uplift alongside capital repricing and lower availability, LCOC&T rises to about $143 per tonne, exceeding our 2030 ETS forecast level even before storage costs are included.  

At $85-100 per tonne, state-backed or strategically critical projects may still proceed; above $120 per tonne, investment timing becomes increasingly uncertain as costs exceed our expected 2030 EU ETS levels. Higher power prices, capital repricing, and reduced availability therefore pose a structural risk to project economics under disruption scenarios, substantially weakening post-2030 scale-up prospects and limiting progress mainly to strategic or state-supported projects. 

Post-conflict recovery 

Once hostilities ease, priorities in the Middle East will center on restoring hydrocarbon production, with CCUS restarting later and pre-2030 projects likely slipping into the mid-2030s or beyond. Higher oil prices may support EOR-linked capture, but momentum across broader industrial emitters could weaken. Over time, the drivers reassert themselves: European and Asian buyers’ scrutiny of lifecycle emissions, Gulf ambitions for blue hydrogen and lower-carbon gas, and the need for credible industrial decarbonization pathways. Together, these factors still support a 10-20 Mtpa regional capture potential, albeit on a slower and more risk-priced trajectory. For global developers, it is important to mitigate conflict-driven cost and supply shocks through inflation-indexed transport and storage tariffs, adjustable policy support (e.g., tax credits or contracts for difference), EPC cost-sharing mechanisms, commodity hedging, and long-term supply agreements, while locking in equipment prices early through strategic procurement to reduce vulnerability to supply-chain disruptions and price volatility.

Authors:

Feriel Adjaout
Senior Analyst, CCUS Research
feriel.adjaout@rystadenergy.com

Yvonne Lam
Head of CCUS Research
yeewen.lam@rystadenergy.com

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