Neither biogas-derived biomethane nor fossil natural gas is universally cheaper or lower-carbon for steam methane reforming (SMR). Natural gas has a mature supply pathway; biomethane can reduce lifecycle emissions when feedstock, methane losses, upgrading energy, and accounting assumptions are favorable. A sound comparison uses delivered methane cost and lifecycle emissions at the same plant boundary.
What changes—and what does not—when the methane comes from biogas?
SMR converts methane and steam into hydrogen and carbon monoxide over a catalyst. The U.S. Department of Energy describes typical operating conditions of 700–1,000 °C and 3–25 bar. The reforming reaction, CH4 + H2O (+ heat) → CO + 3H2, is endothermic, so the process needs heat. A subsequent water-gas-shift reaction, CO + H2O → CO2 + H2, produces additional hydrogen and carbon dioxide.
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Changing the methane source does not remove the need for steam, a suitable catalyst, high-temperature operation, or process heat. It changes the upstream feedstock pathway and potentially the gas conditioning and lifecycle emissions. The DOE describes natural gas as a methane source for hydrogen production by thermal processes such as SMR.
Can biogas be used for steam methane reforming?
Biogas can supply methane to an SMR plant after it has been upgraded to biomethane and conditioned to meet the reformer’s feed specifications. Raw biogas is not interchangeable with pipeline-quality natural gas: it contains carbon dioxide and water and may contain contaminants such as hydrogen sulfide. The European Commission Joint Research Centre describes upgrading as removing carbon dioxide and contaminants, then conditioning the gas for the intended end use.
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Before considering a switch, compare a representative gas analysis with the reformer supplier’s allowable feed composition and contaminant limits. The required cleanup, compression, connection, and controls depend on the actual raw-gas composition and equipment. Do not assume raw biogas can be routed directly into an existing natural-gas reformer.
Which feedstock is cheaper for SMR?
The available evidence does not establish a universal cost winner or a current delivered price for a specific SMR site. The International Energy Agency’s 2025 biogas and biomethane outlook identifies crop residues, manure, biowaste, and woody biomass as possible feedstock categories, and notes that project economics depend on plant scale, feedstock composition and quality, location, collection radius, and infrastructure access. It identifies the anaerobic digester as the main cost component of a biogas project; this is production-cost context, not a quoted feed price at an SMR plant gate.
Older IEA estimates likewise show wide variation across regions and project designs. In some cases, waste feedstock may carry zero or negative acquisition cost when disposal fees apply, but collection, treatment, upgrading, transport, and plant integration still affect total cost. Those historical estimates illustrate cost drivers, not current local bids.
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1Repair Windows errors before they cause bigger problems2Fix the driver behind crashes, sound loss and screen glitches3Clear out junk files and repair common Windows errors| Cost or supply factor | Fossil natural gas | Biogas-derived biomethane |
|---|---|---|
| Delivered methane cost | Depends on local gas pricing, transport, and connection. A universal price is not established by the IEA sources cited here. | Depends on feedstock, digester scale, collection and transport, upgrading, and connection. The IEA’s 2025 outlook does not provide a universal delivered price for an SMR site. |
| Feedstock availability and reliability | Uses a mature supply pathway; delivered availability and price remain market- and location-specific. | Potential feedstocks include residues, manure, biowaste, and woody biomass. Reliable volume depends on local quantity, quality, collection radius, and infrastructure (IEA, 2025). |
| Gas quality and cleanup | Must still meet the receiving reformer’s feed specifications. | Raw biogas generally needs removal of carbon dioxide, water, and contaminants such as hydrogen sulfide, followed by end-use conditioning (European Commission Joint Research Centre). |
| Upgrading, compression, and connection | Site-specific delivery and connection costs apply; the sources cited here do not state a common value. | Cleanup/upgrading, compression, transport, and connection can add cost; the amount depends on the project and location (IEA, 2025; European Commission Joint Research Centre). |
| Plant scale and integration | Cost depends on the site and supply arrangement; a comparable universal SMR value is not stated. | Project economics vary with digester scale and integration with gas infrastructure and the reformer (IEA, 2025). |
| Process heat and steam | SMR needs external heat because the reforming reaction is endothermic (U.S. Department of Energy). | The same SMR heat and steam requirements apply; any additional energy used to upgrade or compress gas belongs in the project comparison. |
| Waste, digestate, and other credits | Any credits or costs must be assessed for the specific site and accounting rules; no common value is stated. | Waste-handling revenue, digestate value, carbon credits, or avoided methane emissions may affect project economics, but must be evidenced and consistently accounted for. |
For a procurement comparison, put both options on a matched basis: methane energy delivered at the plant gate, gas quality, collection and transport, cleanup, compression and connection, process heat and steam, utilization, scale, and any defensible waste-handling or environmental credits. A low-cost feedstock at the digester is not necessarily the lowest-cost methane delivered to an operating reformer.
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Does biogas make hydrogen lower-carbon?
It can, but the result depends on the complete supply chain and the lifecycle accounting boundary. The IEA’s Global Hydrogen Review 2024 gives a global pathway estimate of 10–12 kg CO2-equivalent per kg H2 for unabated natural-gas hydrogen. That is not a guaranteed intensity for any individual plant.
A 2016 peer-reviewed life-cycle assessment by Hajjaji and co-authors estimated 5.59 kg CO2-equivalent per kg H2 for its modeled biogas-reforming system, reporting roughly half the lifecycle emissions of the conventional SMR systems in its comparison. The study included biogas production, reforming, construction, and decommissioning. Its result was influenced by assumptions including digestate displacing artificial fertilizer and recycling credits for construction materials and equipment; it should not be treated as a universal biomethane-hydrogen value.
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These two figures are not a controlled, contemporary head-to-head comparison: they come from different sources and methods. A project assessment needs aligned assumptions for functional unit, geography, plant scale, feedstock production, methane leakage, upgrading electricity and heat, digestate treatment, construction, carbon allocation, and any captured or stored carbon dioxide.
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Why methane leakage and accounting choices matter
Methane losses in production and delivery can materially affect the lifecycle result for either pathway. The IEA’s 2025 methane-intensity chart calculates supply methane intensity by dividing emissions by biogas and biomethane production; its denominator is 2 EJ of production in 2023. That denominator describes the chart’s calculation basis, not the quantity available as SMR feedstock or a plant-specific leakage rate.
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Biomethane results also depend on how the assessment treats the original waste stream, digestate, avoided emissions, and co-product allocation. A favorable credit can lower a modeled result, but only when its counterfactual and allocation method are appropriate to the project being compared.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.How does carbon capture change the comparison?
Capture scope matters. Conventional SMR produces a concentrated process-carbon-dioxide stream as well as a more diluted furnace-gas stream. The IEA distinguishes capture of the process stream alone from capture of both streams; these configurations have different costs and emissions reductions. Therefore, “SMR with carbon capture” is not a single emissions outcome, and capturing carbon at the hydrogen plant alone does not settle lifecycle intensity. Upstream natural-gas emissions must also be considered.
For a fair comparison, state which streams are captured, how much carbon is captured and stored, and whether upstream emissions are included. Do not describe SMR with capture as zero-emission without a defined lifecycle boundary and capture scope.
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- Define the plant boundary. Specify whether the comparison ends at the reformer gate, hydrogen production, or delivered hydrogen, and use the same functional unit for both pathways.
- Establish the feed specification. Obtain representative gas composition and variability data, then check them against the reformer’s feed requirements. For raw biogas, identify the required carbon-dioxide, water, and contaminant removal.
- Build delivered-cost cases. Include feedstock or gas price, collection and transport, upgrading, compression, connection, process heat and steam, utilization, and scale. Include waste, digestate, or carbon revenues only where a project can substantiate them.
- Build matched lifecycle cases. Use consistent assumptions for methane leakage, feedstock production, upgrading energy, digestate, construction, carbon allocation, and any capture and storage.
- Test sensitivities before selecting a pathway. Vary feedstock quality and availability, collection distance, methane loss, upgrading energy, plant utilization, credit eligibility, and capture scope. The preferred option can change when these inputs change.
The result should be a site-specific delivered-cost and lifecycle-emissions comparison, not a generic claim that one methane source is always cheaper or cleaner.
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