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Neither feedstock is always cheaper or lower-carbon for steam methane reforming (SMR). Natural gas has a mature supply pathway; biogas-derived biomethane may reduce lifecycle emissions when feedstock, methane losses, upgrading energy and accounting assumptions are favorable. The useful comparison is between delivered methane and lifecycle emissions at the same plant boundary—not between the words “biogas” and “natural gas” in isolation.
Can biogas be used for steam methane reforming?
Yes, after it has been upgraded and conditioned to meet the reformer’s feed specifications. SMR uses methane, steam and a catalyst at high temperature. The U.S. Department of Energy describes typical operating conditions of 700–1,000 °C and 3–25 bar. The endothermic reforming reaction is CH4 + H2O (+ heat) → CO + 3H2; heat must be supplied. A subsequent water-gas-shift reaction, CO + H2O → CO2 + H2, produces more hydrogen and carbon dioxide.
For procurement and engineering, distinguish raw biogas from biomethane. Raw biogas 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 its end use. Do not assume raw biogas can go straight into an existing natural-gas reformer: verify its composition, the reformer’s feed limits and the required cleanup with the equipment supplier.
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The practical comparison is between a plant’s delivered natural gas and a compliant stream of biogas-derived methane. The table identifies the factors that can shift the result; it does not imply a universal winner or supply prices where none are established.
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| Comparison factor | Natural gas | Biogas-derived biomethane |
|---|---|---|
| Delivered methane cost | Depends on the local gas price, delivery terms and connection. The reviewed sources do not establish a price for a particular plant or market. | Depends on feedstock, project scale, collection radius, upgrading, transport and infrastructure. Waste may have zero or negative acquisition cost where disposal fees apply, but that does not make the finished gas free. |
| Feedstock availability and reliability | Uses a mature supply pathway; availability and reliability still depend on the site’s network, contract and local conditions. | Can be made from feedstocks including crop residues, manure, biowaste and woody biomass. Supply depends on local quantities, quality, collection radius and competing uses. |
| Raw-gas composition and cleanup | Supplied natural gas must meet the plant’s feed specification. | Raw biogas contains CO2 and water and may contain contaminants. Upgrading and conditioning are required to meet the reformer’s specification. |
| Upgrading and compression energy | Account for the energy and cost of delivery and any site conditioning required. | Include energy for cleanup, upgrading and compression, plus connection and transport requirements. These can erode both cost and emissions advantages. |
| Plant scale and integration | Economics depend on plant utilization, supply access and integration with the SMR. | Economics depend on digester and upgrading scale, feedstock logistics and integration. The International Energy Agency identifies the anaerobic digester as the main cost component of a biogas project. |
| Lifecycle emissions and methane leakage | Include upstream and midstream emissions as well as emissions at the hydrogen plant; natural-gas methane losses matter. | Include feedstock production or collection, methane losses, upgrading energy and the treatment of waste and digestate. Lower emissions are possible, but not guaranteed. |
| Carbon-capture boundary | Capture can target concentrated process CO2, the more diluted furnace-gas stream, or both; the capture scope changes cost and reductions. Upstream emissions remain relevant. | Apply the same explicit capture boundary to the reformer and associated streams. A low feedstock footprint does not by itself establish the emissions of hydrogen after capture and upstream processes. |
| Credits and waste-system assumptions | State the emissions boundary and any credits consistently; do not omit upstream gas emissions. | State whether the analysis credits avoided waste emissions, digestate displacing artificial fertilizer, or other benefits. Credits can materially affect a modeled result. |
Is biogas SMR cheaper than natural-gas SMR?
There is no general cost result. The International Energy Agency’s 2025 biogas and biomethane outlook identifies feedstock composition and quality, project size, location, collection radius and infrastructure access as important economic drivers. It identifies the anaerobic digester as the main cost component of a biogas project. Those are production-cost drivers, not a delivered biomethane quote for a specific SMR plant.
Historical IEA estimates likewise show wide variation among regions and project designs, with digester installation accounting for a substantial share in the cases examined. They are useful for understanding cost drivers, not as current local bids. A waste feedstock can carry a zero or negative acquisition cost where a disposal fee is paid, while collection, treatment, upgrading, compression, transport and plant integration still add costs.
Build a comparable delivered-cost case
Compare the feeds at the same plant gate and on the same energy or methane-content basis. For biomethane, include the full chain from feedstock to compliant gas; for natural gas, use the delivered cost and conditions that actually apply to the site. Include:
- Feedstock acquisition, collection, transport and storage, including the distance over which material must be gathered.
- Digestion, gas cleanup and upgrading, compression, connection and any conditioning needed to meet feed specifications.
- Process heat and steam, plant utilization, scale, reliability and integration costs.
- Only defensible revenues or credits, such as waste-handling fees, digestate value, carbon credits or avoided methane emissions, with the eligibility and accounting basis made explicit.
Then test local supply volumes and quality against the reformer’s continuous demand. A low-cost feedstock that cannot be secured at the required volume or specification is not a like-for-like alternative to a dependable gas supply.
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Does biogas make hydrogen lower-carbon?
It can, but the result depends on the full lifecycle and its accounting. The IEA’s Global Hydrogen Review 2024 gives a global estimate of 10–12 kg CO2-equivalent per kg H2 for unabated natural-gas hydrogen. That is a pathway-level estimate, not a guaranteed value for a particular SMR plant.
A 2016 life-cycle assessment by Hajjaji and colleagues estimated 5.59 kg CO2-equivalent per kg H2 for a modeled biogas-reforming system, about half the lifecycle emissions of conventional SMR systems in that study’s comparison. Its boundary included biogas production, reforming, construction and decommissioning. The result was influenced by assumptions about digestate displacing artificial fertilizer and recycling credits for construction materials and equipment. It is a study-specific estimate, not a general biomethane emissions factor.
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Those two figures are not a controlled contemporary comparison: they come from different sources and methods. Do not conclude that every biogas-based plant emits less than every natural-gas plant by comparing the values alone. A fair project analysis aligns the functional unit, geography, plant scale, feedstock production, methane leakage, upgrading electricity and heat, digestate treatment, construction, carbon allocation and treatment of captured or stored CO2.
Track methane losses and credit assumptions
Methane leakage can change the climate result, so it belongs in the lifecycle inventory rather than in a footnote. The IEA’s 2025 methane chart calculates supply methane intensity as emissions divided by biogas and biomethane production; its denominator is 2 EJ of production in 2023. That figure describes the chart’s calculation basis, not the amount of biogas available as SMR feedstock.
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For a project comparison, document how methane losses are measured or estimated at each relevant stage, the electricity and heat used in upgrading, and whether digestate receives a fertilizer-displacement credit. Report both the physical emissions and any credited result clearly enough that a reader can see which assumptions drive the outcome.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.How does carbon capture change the comparison?
SMR produces CO2 in more than one stream. The IEA distinguishes concentrated process CO2 from the more diluted furnace-gas stream in conventional SMR. Capturing only process CO2 and capturing both streams have different costs and emissions reductions. State which streams are included rather than describing SMR with capture as “zero-emission.”
Capture at the hydrogen plant also does not settle lifecycle intensity. The IEA notes that upstream and midstream emissions must be addressed when carbon capture is applied to natural-gas hydrogen. A robust comparison should specify capture scope and rate, the fate of captured CO2, and upstream emissions for either feedstock.
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Screen both pathways using matching plant assumptions, then commission site-specific engineering, lifecycle analysis and commercial quotes before an investment decision. The reviewed evidence does not specify a location, feedstock blend, plant scale, gas-quality specification or local utility and feedstock prices, so it cannot settle the ranking for an individual project.
Quick Recap
- Define the plant boundary. Fix the hydrogen output basis, plant scale and utilization, feed delivery point, process heat assumptions, and whether carbon capture is included.
- Obtain compliant-gas specifications. Confirm the reformer’s allowable composition and contaminants, and determine the upgrading, conditioning, compression and monitoring needed to meet them.
- Secure supply evidence. For biomethane, validate feedstock volume, composition, collection radius, seasonal variation and supply reliability. For natural gas, confirm site access, delivery terms and relevant upstream data.
- Build matched cost and lifecycle models. Use consistent energy and emissions boundaries, include methane losses and upgrading energy, and show waste, digestate and carbon credits separately from gross emissions and costs.
- Run sensitivities. Test the variables most likely to change the decision, including scale, feedstock quality and price, collection distance, low-carbon electricity availability, methane leakage and carbon-removal scope. A 2026 institutional record for a biogas-hydrogen techno-economic assessment also identifies scale, carbon removal and low-carbon electricity as sensitivities, but the abstract-level information does not establish a general numerical outcome.
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