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Biogas and upgraded biogas (biomethane) can replace fossil natural gas as the methane feedstock for steam methane reforming (SMR), but the switch does not automatically make hydrogen carbon neutral. The result depends on how the gas was produced, methane losses during upgrading and delivery, the reformer’s efficiency and heat supply, and which emissions a lifecycle assessment counts. The strongest approach is to verify the gas supply chain, reduce energy use and methane losses at the plant, account for furnace emissions, and capture carbon dioxide from relevant process and combustion streams.
How biogas reforming produces emissions
In SMR, methane reacts with high-temperature steam over a catalyst to produce hydrogen and carbon monoxide. A subsequent water-gas shift reaction converts carbon monoxide and steam into more hydrogen and carbon dioxide; pressure-swing adsorption then separates hydrogen from carbon dioxide and other impurities. The U.S. Department of Energy describes typical steam-reforming conditions as 700°C–1,000°C and 3–25 bar.
There are two main carbon pathways to track: carbon in the methane feed that becomes process carbon dioxide, and fuel burned to provide heat for the endothermic reforming reaction. The DOE’s process overview explicitly notes that heat must be supplied for the reaction to proceed. A plant assessment should therefore include the reformer furnace or other heat source, not just the origin of its methane.
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Raw biogas can contain methane and carbon dioxide along with impurities; upgraded biogas, commonly called biomethane, has had much of the carbon dioxide and contaminants removed to meet a defined specification. Whether the gas is used raw or upgraded affects the process configuration and the emissions associated with conditioning, transport, and use. The renewable origin of the methane alone does not establish the plant’s total climate impact.
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What reported emissions reductions do—and do not—show
Published results illustrate the potential, but they use different systems and boundaries. The figures below should not be read as a single ranking or as guaranteed performance for a particular facility.
| Finding | Reported result | Scope and qualification |
|---|---|---|
| U.S. SMR facility emissions | 9.35 kg CO2e/kg H2 direct emissions; 11.2 kg CO2e/kg H2 including upstream emissions | Energy Reports study authors, 2022; estimates based on facility-level emissions data for 33 U.S. SMR hydrogen facilities. The two values use different emissions boundaries. |
| Higher hydrogen-production efficiency | 5.9% lower global-warming impact for a modeled 5% efficiency increase; 11.1% lower for a modeled 10% increase | Energy Reports study authors, 2022; modeled changes, not measurements of a universal plant upgrade. |
| Natural gas replaced by biomethane | 53.7% lower impact | Energy Reports study authors, 2022; a modeled scenario whose outcome depends on the study’s assumptions and should not be generalized to all biomethane supplies or plants. |
| Landfill gas feedstock | 68.2% lower impact | Energy Reports study authors, 2022; a separate modeled pathway, not interchangeable with the biomethane scenario. |
| Biomass gasification | 78.1% lower impact | Energy Reports study authors, 2022; this is a biomass-gasification result, not a biogas-reforming result. |
| Modeled biogas-to-hydrogen system | 5.59 kg CO2-eq/kg H2 | International Journal of Hydrogen Energy study record, 2016. The indexed record describes roughly half the lifecycle emissions of the conventional SMR systems used for comparison; its result includes credits such as displaced fertilizer from digestate and recycling. It is not a like-for-like comparison unless boundaries and allocation assumptions match. |
| Electrified biogas reforming with CO2 separation | Up to 76% of biogenic carbon recovered and up to −9 kg CO2/kg H2 | Politecnico di Milano study, 2024; modeled outcomes for a particular configuration, not measured plant results or a general commercial guarantee. |
The 2022 facility study also reports that replacing natural gas with biomethane reduced modeled impact by 53.7%, but its result is scenario-specific. It cannot by itself predict the outcome for a site with different feedstock production, upgrading energy, methane losses, heat supply, or capture coverage. The 2016 biogas LCA result also depends partly on credits for digestate and recycling, so comparing it directly with the facility study’s values would be misleading without aligning lifecycle boundaries and allocation methods.
Reduce emissions in the order that makes them measurable
1. Verify the gas source and methane losses
Document whether the input is raw biogas, upgraded biomethane, landfill gas, or another source, and trace its origin through production, conditioning, storage, and delivery. Ask suppliers for measured or credibly estimated methane emissions at digestion, upgrading, and other supply-chain stages, as well as the energy used for upgrading and transport. The EU Joint Research Centre’s 2024 report addresses methane-emissions measurement, mitigation practices, and accounting methods for EU biogas and biomethane supply chains; its geographic scope is the EU.
Methane lost before the gas reaches the plant can materially affect the lifecycle result. A renewable-gas certificate or label is not a substitute for supply-chain emissions data.
2. Improve conversion efficiency and heat integration
Track energy and methane consumption per kilogram of hydrogen, then identify opportunities to reduce them. Better heat integration and waste-heat recovery can reduce the energy needed per unit of hydrogen; reducing unreacted methane also limits losses of feedstock. The 2022 facility-data study models lower impact with improved production efficiency, while UK Environment Agency guidance directs plant designers to maximize energy and process efficiency. The size of the benefit at a specific facility must be established from its own operating data.
3. Count and decarbonize the heat supply
Because reforming requires heat, switching to biomethane does not erase emissions from fuel burned in the furnace. Include combustion emissions in the plant inventory and evaluate the available heat-supply options using the same lifecycle boundary as the feedstock comparison. If electricity or another heat source replaces some furnace fuel, include its emissions and any resulting changes to plant performance rather than treating the substitution as emissions-free.
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4. Capture carbon from the streams that matter
Assess capture coverage across process carbon dioxide, reformer flue gas, and carbon-containing purification off-gas. A capture rate is meaningful only when its boundary, operating conditions, and averaging period are stated. Capturing a concentrated process stream alone does not establish the fraction of the facility’s total carbon emissions captured if furnace exhaust or other relevant streams are excluded.
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5. Control venting, flaring, and off-design losses
Include routine and non-routine operating conditions in the emissions plan. Minimize venting and flaring of methane and hydrogen, and quantify emissions during startup, shutdown, outages, and flexible operation. Capture and efficiency can decline outside steady-state operation, so annual performance should reflect actual operating hours and losses rather than design-point claims alone.
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Build a fair lifecycle comparison
Compare options using the same functional unit—commonly kilograms of CO2-equivalent per kilogram of hydrogen—and a clearly stated lifecycle boundary. A direct plant figure excludes some upstream emissions; a lifecycle figure may include feedstock production, upgrading, transport, electricity, and other inputs. Keep those categories visible so that a lower direct-emissions value is not mistaken for a lower total footprint.
- State the feedstock pathway and origin: raw biogas, upgraded biomethane, landfill gas, or fossil natural gas.
- Report methane leakage assumptions and the energy used for digestion, upgrading, storage, and delivery.
- Specify plant energy use, efficiency, heat source, and whether the reported result reflects steady-state or flexible operation.
- Identify which carbon streams are included in any capture rate and how capture performance is averaged.
- Disclose lifecycle boundary, functional unit, and any allocation or credits, including digestate fertilizer or recycling credits.
For a site-specific result, use local feedstock data, measured methane losses, plant energy and emissions records, and a consistent lifecycle method. Headline values from studies with different boundaries, credits, and process configurations are not directly interchangeable.
Can biogas reforming be carbon negative?
Some modeled configurations report net-negative outcomes, but that label depends on the modeled system and accounting. The 2024 Politecnico di Milano result of up to −9 kg CO2/kg H2 is tied to an electrified biogas-reforming configuration with CO2 separation; it is not a measured result or a general expectation for biogas reformers. A defensible claim must explain how biogenic carbon is counted, how much is captured and stored or otherwise managed, and which upstream emissions and credits are included.
For the same reason, “carbon neutral” is not an automatic property of hydrogen made from biogas. The feedstock’s biological origin does not cancel methane leakage, upgrading and transport energy, furnace combustion, electricity use, or operational emissions. State the boundary and assumptions alongside any net-emissions claim.
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