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Neither steam methane reforming (SMR) nor electrolysis is the best choice everywhere. SMR uses natural gas and established process infrastructure; electrolysis uses electricity to split water. The right fit depends on local energy costs and emissions, plant scale and operating pattern, and—if SMR uses carbon capture—the capture rate and the rest of the fuel and CO₂ supply chain.
How do SMR and electrolysis make hydrogen?
| Route | How it works | Main inputs and operating considerations |
|---|---|---|
| Steam methane reforming (SMR) | High-temperature steam reacts with methane to form hydrogen and carbon monoxide. A water-gas shift reaction converts carbon monoxide and steam into carbon dioxide and additional hydrogen; pressure-swing adsorption then separates hydrogen from carbon dioxide and other impurities. | Natural gas, steam, heat and a catalyst. The U.S. Department of Energy (DOE) describes SMR operation at 700–1,000°C and 3–25 bar. The route is mature and uses existing gas-pipeline infrastructure. |
| Electrolysis | Electricity splits water into hydrogen and oxygen. | Water and electricity. DOE describes alkaline, proton-exchange membrane (PEM) and solid-oxide electrolyzers. Alkaline systems generally operate below 100°C, PEM systems around 70–90°C, and solid-oxide systems around 700–800°C; solid-oxide systems can use heat to reduce electrical input. |
DOE says 95% of hydrogen produced in the United States is made by natural-gas reforming in large central plants. That is a U.S.-specific figure on the DOE page, whose publication date is not stated; it is not a global share.
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Which route has lower emissions?
The production method alone does not determine the climate impact. The comparison needs the same lifecycle boundary: emissions from fuel and electricity supply, production, and any relevant equipment or infrastructure must be treated consistently.
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SMR produces carbon dioxide as part of the reforming process, and natural-gas supply can add upstream emissions. The International Energy Agency (IEA) estimates that unabated natural-gas hydrogen emits 10–12 kg CO₂-equivalent per kg of hydrogen. Across all hydrogen production, global emissions reached 920 Mt CO₂ in 2023, according to the IEA’s 2024 accounting.
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Electrolysis
Electrolysis has no direct emissions at the production point in the IEA accounting, but its lifecycle result depends heavily on how its electricity is generated. In the IEA’s comparison, electricity-generation intensity must be below 200–240 g CO₂/kWh for electrolytic hydrogen to emit less than SMR hydrogen. This is a comparison threshold, not a universal guarantee for every plant or accounting method.
The IEA also estimates 0.4–2.7 kg CO₂-equivalent per kg of hydrogen in embedded emissions from renewable-asset construction and manufacturing. These are emissions associated with building and manufacturing the assets, rather than emissions at the electrolyzer; the IEA says most standards and schemes at the time excluded them.
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SMR with carbon capture
Carbon capture and storage (CCUS) can reduce emissions released at an SMR plant, but it does not by itself eliminate lifecycle emissions. Upstream and midstream emissions—including those associated with natural-gas supply—also need to be addressed. In its global 2023 accounting, the IEA estimates that 75–95% of hydrogen-production emissions occur directly at the production point, where CCUS can reduce them.
For SMR, the IEA estimates abatement costs of USD 60–85 per tonne of CO₂ for 55–70% capture, and USD 85–110 per tonne for capture above 90%. These are estimates, not prices or guaranteed capture performance for a particular project.
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Is electrolysis cheaper than SMR?
There is no universal cost winner. SMR economics depend substantially on natural-gas prices and the cost of handling captured CO₂, if applicable. Electrolysis economics depend on electricity prices and availability, equipment and operating costs, and how intensively the plant can run. Financing, scale and the required delivery pressure and purity also matter.
The IEA’s global-average levelised-cost chart, last updated on 24 September 2020, modeled 2019 and 2050 cases. For its 2019 assumptions, it used lower-heating-value efficiencies of 76% for SMR without CCUS, 69% for SMR with CCUS, and 64% for electrolysis; the electrolysis assumption was 74% in the 2050 case. The model also incorporated fuel and electricity prices, capital and operating costs, utilization hours, capture rates and a representative discount rate. These historical modeled assumptions explain why costs vary; they are not current universal prices or project bids.
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For context, a separate IEA route chart uses the following energy-input assumptions. They are methodology assumptions, not guaranteed real-plant specifications:
| Route in IEA chart | Assumed energy demand | Qualification |
|---|---|---|
| Low-temperature electrolysis | 50 kWh/kg H₂ | Includes compression to 30 bar; IEA chart assumption published in 2023 for its 2021-route comparison. |
| SMR without CO₂ capture | 44.5 kWh/kg H₂ of natural gas | IEA chart assumption published in 2023 for its 2021-route comparison. |
| SMR with 60% capture | 45.0 kWh/kg H₂ of natural gas | IEA chart assumption published in 2023 for its 2021-route comparison. |
| SMR with 93% capture | 49 kWh/kg H₂ of natural gas plus 0.8 kWh/kg H₂ of electricity | IEA chart assumption published in 2023 for its 2021-route comparison. |
Those energy figures are not directly interchangeable with levelised production costs: a project comparison also needs local prices, performance, financing and a shared system boundary. The broad figures here cannot establish a current cost for a specific site.
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What should determine the route for a project?
Assess the site and hydrogen specification before choosing a production route. A useful comparison uses the same output purity, delivery pressure, plant scale, operating profile and lifecycle-emissions convention for both options.
- Consider SMR where reliable natural-gas supply, established central-plant infrastructure and a mature process are valuable. If lower emissions are required, evaluate the actual capture rate alongside upstream methane and other supply-chain emissions, plus CO₂ transport and storage.
- Consider electrolysis where sufficiently low-emissions electricity is available at a workable price, including through renewable or nuclear power integration. Grid electricity is not automatically low-emissions; include its generation emissions and consider the electrolyzer type and operating profile.
- Compare local economics using the relevant geography and year, gas and electricity prices, capacity and utilization, equipment and financing costs, and any capture, transport and storage costs.
- Set the boundary first so both options account for supply-chain emissions and delivery requirements in the same way. State whether embedded asset emissions are included.
The DOE’s electrolysis guidance puts the key trade-off plainly: “The source of the required electricity—including its cost and efficiency, as well as emissions resulting from electricity generation—must be considered when evaluating the benefits and economic viability of hydrogen production via electrolysis.”
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