Neither steam methane reforming (SMR) nor electrolysis is the best choice in every case. SMR uses natural gas and established process infrastructure; electrolysis uses electricity to split water and can have lower emissions when that electricity is sufficiently low-carbon. The practical choice depends on local fuel and power prices, emissions, plant scale and utilization, infrastructure, and—if SMR is used with carbon capture—the capture rate and the rest of the CO₂ supply chain.
How do SMR and electrolysis make hydrogen?
Both processes produce hydrogen, but they use different inputs and create different emissions profiles. The production method alone does not tell you the lifecycle emissions or cost of the hydrogen.
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Steam methane reforming
SMR reacts methane in natural gas with high-temperature steam. The U.S. Department of Energy describes reforming at 700–1,000°C and 3–25 bar in the presence of a catalyst. The initial reaction produces carbon monoxide and hydrogen; a water-gas shift reaction then converts carbon monoxide and steam into carbon dioxide and additional hydrogen. Pressure-swing adsorption separates carbon dioxide and other impurities from the hydrogen stream.
SMR is a mature process that can use established natural-gas pipeline infrastructure. 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. figure, not a global share, and the reviewed page does not state a publication date.
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Electrolysis
Electrolysis uses electricity to split water into hydrogen and oxygen. DOE describes three main electrolyzer types: alkaline, proton exchange membrane (PEM), and solid oxide. Their electrolytes and operating conditions differ. Commercial alkaline systems generally operate below 100°C; PEM systems around 70–90°C; and solid-oxide systems around 700–800°C. Solid-oxide electrolyzers can use heat to reduce the electricity they need.
Electrolysis therefore shifts much of the emissions question to the electricity supply. As DOE notes, the electricity’s cost, efficiency, and generation emissions all matter when assessing the route’s economic and environmental benefits.
Which route has lower emissions?
Compare lifecycle emissions, not just what leaves the production plant. The boundary should account for the energy supply and, where relevant, fuel production and transport, equipment construction, and carbon capture and storage (CCUS).
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Unabated SMR
SMR produces carbon dioxide as part of the process and also depends on natural gas supplied through an upstream and midstream chain. The International Energy Agency (IEA) estimates that unabated natural-gas-based hydrogen produces 10–12 kg CO₂-equivalent per kg of hydrogen. That estimate is from the IEA’s 2024 reporting and should be understood as an emissions estimate, not a guaranteed result for every plant.
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Electrolysis
Electrolyzers have no direct emissions at the production point in the IEA’s accounting, but the electricity used to run them can have substantial emissions. In its 2024 comparison, the IEA estimates that electricity generation intensity must be below 200–240 g CO₂/kWh for electrolytic hydrogen to emit less than SMR hydrogen under that comparison’s assumptions. This is a comparison threshold, not a universal cutoff for every project or lifecycle boundary.
The IEA also estimates embedded emissions of 0.4–2.7 kg CO₂-equivalent per kg of hydrogen from constructing and manufacturing renewable-energy assets. Those are asset-related emissions, distinct from emissions at the electrolyzer; the IEA says most standards and schemes at the time excluded them. A project’s reported intensity can therefore depend on the accounting rules it follows.
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SMR with carbon capture
CCUS can reduce SMR’s production-site emissions, but it does not make them disappear. In the IEA’s global 2023 accounting, 75–95% of hydrogen-production emissions occurred directly at the production point, where CCUS can reduce them. Upstream and midstream emissions—including those associated with natural-gas supply—also need to be addressed.
The IEA estimates SMR 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 in the IEA’s 2024 reporting, not quotes or guaranteed costs for an individual project. A stated capture rate also does not, by itself, describe the project’s full lifecycle emissions.
Is electrolysis cheaper than SMR?
There is no universal cost winner. The price and availability of natural gas and electricity, plant utilization, capital and operating costs, financing, and the project’s delivery requirements can all change the result. For SMR with CCUS, capture equipment and CO₂ transport and storage also matter; for electrolysis, the price and operating profile of electricity are particularly important.
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The IEA’s global-average levelised-cost chart, last updated on 24 September 2020, models 2019 and 2050 cases. Its assumed lower-heating-value efficiencies were 76% for SMR without CCUS, 69% for SMR with CCUS, and 64% for electrolysis in 2019, rising to 74% for electrolysis in 2050. These are historical model assumptions—not current universal prices, project bids, or guarantees of real-plant performance. The chart also depends on assumptions about fuel and electricity prices, utilization hours, capture rates, capital and operating costs, and discount rates.
A separate IEA route comparison published in 2023 used these energy-input assumptions:
| Route in the IEA comparison | Assumed energy input per kg of hydrogen | Qualification |
|---|---|---|
| Low-temperature electrolysis | 50 kWh | Includes compression to 30 bar; IEA chart methodology assumption. |
| SMR without CO₂ capture | 44.5 kWh of natural gas | IEA chart methodology assumption. |
| SMR with 60% capture | 45.0 kWh of natural gas | IEA chart methodology assumption. |
| SMR with 93% capture | 49 kWh of natural gas plus 0.8 kWh of electricity | IEA chart methodology assumption. |
These energy inputs describe the comparison’s assumptions; they are not performance specifications for every operating plant. A current project estimate cannot be derived from these broad, historical sources alone.
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What should you compare for a real project?
Before choosing a route, make sure the options being compared deliver equivalent hydrogen under the same assumptions. Differences in geography, system boundary, output pressure, purity, scale, or operating profile can make headline cost and emissions figures misleading.
- Location and date: Specify where the project is and which year’s fuel, electricity, and financial assumptions apply.
- Energy inputs: Use local natural-gas and electricity prices. For electrolysis, include the electricity-generation emissions intensity and the electrolyzer’s operating profile.
- Comparable output: Compare hydrogen at the same purity and delivery pressure, and at a similar production scale.
- Utilization and financing: State the plant’s expected operating hours, capital and operating costs, and financing assumptions.
- SMR capture and supply chain: Specify the capture rate and account for upstream methane and other gas-supply emissions, as well as CO₂ transport and storage.
- Electrolyzer and power source: Identify the electrolyzer type and whether electricity comes from the grid or a dedicated source; do not assume grid electricity is low-emissions.
- Accounting boundary: Use the same lifecycle convention for both routes, including how embedded equipment emissions are treated.
Which route fits your needs?
SMR may fit where gas and established infrastructure are priorities
SMR may be a practical fit where reliable natural-gas supply and mature central-plant infrastructure are available and valued. If lower emissions are a requirement, assess the actual capture configuration and rate, and include emissions from upstream and midstream gas supply rather than judging the route by its production-site capture figure alone.
Electrolysis may fit where low-emissions power is available
Electrolysis may be a better fit where sufficiently low-emissions electricity is available at a workable price, or where the project can integrate with renewable or nuclear power. The power source and operating profile are central to the emissions and cost result; a grid connection does not automatically mean low-carbon hydrogen.
Make the decision against the project’s actual constraints
For a site-specific decision, compare delivered hydrogen cost and lifecycle emissions on a like-for-like basis. Include the required output scale, reliability, pressure and purity, available infrastructure, and the full costs of fuel or power and any CO₂ handling. The broad comparisons above establish the trade-offs, but not a recommendation for an unspecified location or project.
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