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Yes: steam methane reforming (SMR) can use biogas-derived biomethane instead of fossil natural gas, and a modeled 2022 study found a substantial emissions reduction in its biomethane scenario. But the switch does not automatically make hydrogen carbon neutral. The result depends on how the gas is produced and upgraded, methane losses from production through delivery, the reformer’s energy use and heat source, and which emissions a lifecycle assessment counts. The most credible reductions combine verified low-leakage feedstock, efficient operation, control of routine losses, and carbon capture that accounts for both process and furnace emissions.
How SMR emissions arise
In steam methane reforming, high-temperature steam reacts with methane over a catalyst to produce hydrogen and carbon monoxide. A water-gas shift reaction then converts carbon monoxide and steam into more hydrogen and carbon dioxide. Pressure-swing adsorption separates hydrogen from carbon dioxide and other impurities. The U.S. Department of Energy describes typical process conditions as 700°C–1,000°C and 3–25 bar.
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There are two major carbon pathways to track: carbon in the methane feed that becomes process CO2, and fuel burned to provide the heat required by the endothermic reforming reaction. Upstream emissions also matter: producing, upgrading, transporting and using gas can release methane or consume energy, while electricity and other plant operations add emissions. Counting only the reformer’s process stream misses part of the footprint.
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Can biogas be used in SMR, and what changes?
Biogas from sources such as anaerobic digestion can be used after appropriate conditioning; upgrading it to biomethane raises its methane content so it can serve as a methane feedstock. The precise treatment needed depends on the gas and the reformer’s requirements. The carbon in biogas is biogenic, but its climate impact still depends on the full pathway, including methane leakage, upgrading energy, transport and plant operation.
Do not treat “biogas,” “biomethane,” and “landfill gas” as interchangeable labels for one emissions result. They refer to different feedstock pathways and can have different production, collection, upgrading and accounting assumptions. For example, a modeled landfill-gas result is not evidence that every digester-derived biomethane supply will achieve the same reduction.
What published estimates show—and what they do not
A 2022 Energy Reports study used facility-level emissions data from 33 U.S. SMR hydrogen facilities. It estimated 9.35 kg CO2e per kg H2 for direct emissions and 11.2 kg CO2e per kg H2 after including upstream emissions within that study’s lifecycle boundary. The same authors modeled several changes to the baseline; these percentages are scenario-specific impact reductions, not guaranteed results at an operating plant.
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|---|---|---|
| Increase hydrogen production efficiency by 5% | 5.9% lower global-warming impact | Modeled by the 2022 Energy Reports study; not a measured result for every facility. |
| Increase hydrogen production efficiency by 10% | 11.1% lower global-warming impact | Modeled by the 2022 Energy Reports study; scenario-specific. |
| Replace natural-gas feedstock with biomethane | 53.7% lower impact | Modeled by the 2022 Energy Reports study under its assumptions; not a universal biomethane value. |
| Use landfill gas as feedstock | 68.2% lower impact | A distinct modeled pathway in the 2022 study, not a result for all biogas or biomethane. |
| Use biomass gasification | 78.1% lower impact | A separate modeled technology pathway in the 2022 study, not biogas reforming. |
| Biogas-to-hydrogen system | 5.59 kg CO2-eq per kg H2 | A 2016 International Journal of Hydrogen Energy indexed record describes a modeled lifecycle result. It attributes part of the result to digestate fertilizer displacement and recycling credits, so it is not directly comparable with the 2022 estimates without matching boundaries and allocation. |
A separate 2024 Politecnico di Milano study modeled an electrified biogas-reforming configuration with CO2 separation. It reported outcomes of up to 76% of biogenic carbon recovered and up to −9 kg CO2 per kg H2. These are modeled outcomes for that configuration, not measured plant performance or a general commercial guarantee. A negative modeled value depends on the study’s system boundary and carbon accounting.
The figures above answer different questions: some are direct facility emissions, some include upstream emissions, and others describe alternative modeled systems with credits or specific configurations. They should not be ranked as though they used one common lifecycle method.
How to reduce the footprint in practice
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Verify the gas pathway and methane losses
Document the feedstock’s origin and measure, or credibly estimate, methane emissions from production, digestion, upgrading, storage and delivery. Methane escaping before it reaches the reformer can erode the climate benefit of substituting biomethane for fossil gas. The European Commission’s Joint Research Centre issued a 2024 report on methane measurement, mitigation practices and accounting for EU biogas and biomethane supply chains; its geographic scope is the EU, so local assessments should use locally relevant data and rules.
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Improve hydrogen yield and energy efficiency
Reduce energy and methane consumption per unit of hydrogen, limit unreacted methane, and use heat integration and waste-heat recovery where practical. The 2022 facility-data study modeled lower impacts with higher production efficiency, and UK Environment Agency guidance directs designers within its scope to maximize energy and process efficiency. Efficiency gains reduce the amount of feed and energy needed for a given hydrogen output, but their effect should be calculated for the actual plant.
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Include the reformer furnace in the accounting
SMR needs a heat supply. Count combustion emissions from the furnace or other heat source even when the methane feed is biomethane; a lower-carbon feedstock does not, by itself, eliminate emissions from supplying process heat. If heat is electrified or supplied another way, include the emissions and energy inputs associated with that alternative.
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Capture CO2 from the relevant streams
Assess capture from the concentrated process-gas stream as well as reformer flue gas and carbon-containing purification off-gas, where applicable. State which streams are covered and how capture is measured; a capture percentage for one stream is not the same as an overall plant capture rate. UK Environment Agency guidance for hydrogen-production and CO2-capture plant designs within its scope says an overall capture rate of at least 95% should be achieved, with justification required for a lower design rate. It is UK guidance, not a universal legal requirement or proof of achieved performance elsewhere.
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The same guidance says, “You should design plant to maximise the carbon capture efficiency.” Its practical relevance includes designing for operation beyond steady state: capture and efficiency can fall during flexible operation, startup, shutdown or outages, so those periods and associated losses belong in the assessment.
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Prevent operating losses
Minimize routine venting and flaring of methane and hydrogen, and track startup, shutdown, flexible operation and outage emissions. Report how these operating conditions affect methane losses, energy use and CO2 capture rather than relying only on nominal design performance.
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Make the comparison transparent
For any claimed reduction, specify the feedstock pathway and origin, upgrading energy, methane leakage assumptions, electricity and heat inputs, functional unit, lifecycle boundary, capture coverage, operating conditions and allocation credits. A common functional unit is kg CO2e per kg H2, but the number is meaningful only alongside its boundary and assumptions.
How to judge whether a claimed reduction is credible
A useful comparison asks whether the proposed biomethane route and the reference natural-gas route use the same lifecycle boundary, functional unit and allocation method. It also checks whether both include upstream methane, plant heat, electricity, capture performance and operating losses. Feedstock credits—for example, avoided fertilizer production or recycling—should be shown separately or explained clearly because they can materially affect a lifecycle result.
For a facility-specific result, use local feedstock and methane-loss data alongside plant energy and emissions records, then apply one consistent lifecycle method to both cases. The EU Joint Research Centre report is relevant to EU supply-chain measurement and accounting; the UK Environment Agency capture guidance applies to its defined regulatory scope. Neither establishes a universal result for every location or reformer.
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