Steam Methane Reforming (SMR) currently supplies the majority of global hydrogen, predominantly for refining and ammonia production, with typical lifecycle emissions of 8–11 tCO₂ per tonne of H₂. Retrofitting existing SMR units with carbon capture systems is frequently described as "low-hanging fruit" for decarbonization. In reality, economics and abatement performance vary significantly by plant size, configuration, integration options and regional policy environment. At Energy Solutions, we examine where blue hydrogen retrofits truly deliver competitive abatement costs—and where they risk locking in suboptimal assets.
Steam Methane Reforming converts natural gas and steam into hydrogen and CO₂ through reforming and shift reactions, typically followed by a pressure swing adsorption (PSA) unit to polish hydrogen purity. The main emissions levers are:
Retrofitting focuses on capturing process and, optionally, combustion CO₂, and on reducing energy use per unit of hydrogen through efficiency upgrades.
Two broad configurations dominate retrofit discussions:
| Configuration | Share of Emissions Targeted | Overall Capture Rate | Relative Complexity |
|---|---|---|---|
| Process-Only Capture | 60–70% | 50–65% | Moderate |
| Process + Partial Combustion Capture | 80–90% | 70–85% | High |
| Process + Full Combustion Capture | 90–100% | 85–95% | Very High |
The chart below shows a stylised relationship between overall capture rate and relative CAPEX for different retrofit configurations.
Retrofits impose both capital and operating penalties: additional equipment, energy use and integration complexity. Benchmarks include:
| Plant Size | Hydrogen Capacity | Configuration | Retrofit CAPEX | Additional Energy Use |
|---|---|---|---|---|
| Small Industrial SMR | 20–50 ktH₂/year | Process-Only | 70–150 million USD | +10–18% energy per tH₂ |
| Refinery SMR Complex | 80–150 ktH₂/year | Process-Only | 120–250 million USD | +8–15% energy per tH₂ |
| Large Merchant Hydrogen Plant | 150–300 ktH₂/year | Process + Partial Combustion | 250–500 million USD | +15–25% energy per tH₂ |
Figures are stylised and exclude CO₂ transport and storage costs, which can add 10–40 USD/tCO₂ depending on distance, infrastructure and storage type.
The bar chart below compares approximate levelised cost of hydrogen (LCOH) for a set of stylised cases.
Blue hydrogen retrofit economics sit at the intersection of natural gas prices, carbon policy and alternative hydrogen options (notably green hydrogen).
For a representative refinery SMR unit:
With explicit carbon pricing at 80–150 USD/tCO₂, retrofits can be more cost-effective than paying for emissions in many jurisdictions, especially when green hydrogen LCOH remains above 2.5–3.5 USD/kg in 2027–2030.
A large refinery operating three SMR trains with combined capacity of 120 ktH₂/year evaluates a process-only capture retrofit.
Under a carbon price of 100 USD/tCO₂, the project yields a simple payback of 7–10 years and significantly improves the refinery’s Scope 1 profile, with additional strategic value if low-carbon hydrogen is required by downstream customers.
A merchant hydrogen producer delivering to industrial customers pursues deep capture as part of long-term offtake contracts.
The project becomes attractive where long-term offtake contracts include carbon-cost pass-through or premium pricing for low-carbon hydrogen, especially in jurisdictions with strong industrial decarbonization mandates.
The line chart below illustrates how abatement cost can rise at higher capture rates due to increasing complexity and energy penalty.
Blue hydrogen economics are highly sensitive to CO₂ transport and storage infrastructure:
On the hydrogen market side, retrofitted SMR plants may serve internal refinery demand, local industrial users or longer-term hydrogen networks. Contract structures (take-or-pay, indexed to gas and carbon prices) and certification schemes for low-carbon hydrogen will shape project bankability.
Blue hydrogen retrofits are not without controversy.
These risks suggest that blue hydrogen retrofits should be prioritised where plants are efficient, integrated into broader industrial clusters and aligned with a clear regional net-zero strategy, rather than as blanket solutions.
By 2035, blue hydrogen from retrofitted SMR plants is likely to play a transitional role in many systems:
For asset owners considering SMR retrofits, a disciplined screening process is essential.
Many first-wave projects target overall capture rates of 50–70% by focusing on process CO₂ streams. Higher capture rates are technically possible but require capturing dilute flue gas CO₂, which increases CAPEX and energy use.
Retrofits can benefit from existing infrastructure but face integration constraints. New-build plants can optimise layouts for capture from day one. In many cases, well-designed new-build blue hydrogen plants exhibit slightly lower abatement costs than complex retrofits, but retrofits have the advantage of leveraging sunk capital and existing offtake arrangements.
Very important. High upstream methane leakage can significantly increase lifecycle emissions, undermining climate benefits relative to unabated natural gas use. Combining SMR retrofits with strong methane abatement along the gas supply chain is critical to ensure credible lifecycle performance.
In principle, some downstream infrastructure (pipelines, storage, offtake networks) can serve both blue and green hydrogen. However, the SMR units themselves are unlikely to be repurposed; instead, they may be gradually displaced by electrolysers over time, with blue hydrogen acting as a bridge.
Common structures include long-term offtake agreements with low-carbon hydrogen price premia, contracts for difference on carbon price, tax credits for captured and stored CO₂, and participation in industrial decarbonization or cluster funding schemes. These mechanisms provide revenue certainty to cover higher CAPEX and OPEX.
In clusters planning hydrogen pipeline networks, retrofitted SMR plants can act as early anchor suppliers, helping justify investment in shared infrastructure. Over time, additional green hydrogen sources can connect, allowing a gradual shift in the supply mix without stranding pipelines.
Alignment depends on capture rates, upstream methane performance, and the timeline for transitioning towards lower-carbon alternatives. Blue hydrogen can play a role in near- to medium-term decarbonization, but long-term compatibility with 1.5 °C pathways generally requires very high capture rates, low methane leakage and a plan for eventual phase-down of unabated gas use.
From concept to operation, SMR retrofit projects commonly require 5–8 years, including feasibility studies, FEED, permitting, financing and construction. Alignment with refinery or industrial turnaround schedules can significantly influence timing and cost.