The Minimal Methanol Economy: Frequently Asked Questions

The basic concept is described in this blog post:

The Minimal Methanol Economy as a Gap-Filler for High Electrification Scenarios

but to keep it short: "electrify as much as possible and use methanol for the rest".

In contrast to a "hydrogen economy" this minimises molecule use and avoids transporting fiddly gases; any green hydrogen stays inside industry clusters that produce green methanol, ammonia or steel. Pipeline transport and underground storage of hydrogen are avoided.

In contrast to a "methanol economy" (suggested by Fred Asinger, George Olah and others), we suggest to keep methanol usage to a minimum and e.g. avoid applications in land transport and heating that can be electrified. We also avoid fossil production of methanol.

Methanol is used for non-electrified shipping, producing kerosene for long-distance aviation, plastics, and for backup power and district heat when other renewable sources are absent. Methanol is easy to transport and store since it is a liquid in ambient conditions.

The volume of green methanol needed depends how much carbon can be sequestered, how much can be electrified, and how demand changes.

In the default setup, when only 200 MtCO₂/a sequestration is allowed in Europe in 2050, there is around 820 TWh/a of electrolytic hydrogen production:

This hydrogen is all used locally inside industry clusters to produce the following green derivatives: methanol (using excess CO₂ from biomass), ammonia (using nitrogen from the air) and steel (using imported iron ore).

As discussed below, if the sequestration is increased, the model prefers to compensate fossil fuels with carbon dioxide removal (CDR) using the biogenic carbon for sequestration instead of in fuels.

At 400 MtCO₂/a the use of electrolytic hydrogen drops to 250 TWh/a:

At 600 MtCO₂/a it drops to 145 TWh/a:

Biomass is used to produce methanol in our scenarios. Since biomass has excess carbon compared to methanol, the additional carbon can be upgraded with electrolytic hydrogen to make the most of the available carbon, so-called e-biomethanol. This allows the model to avoid expensive direct air capture (DAC).

Only sustainable biomass sources are allowed in the model. This means the model is forced to used wastes and residues that do not cause any additional land use. In particular, dedicated energy crops such as corn/maize, other cereals or rape seed, are not allowed. This would be a substantial change to the biomass substrates used today.

The biomass sources are split into two categories: solid biomass and biogas. Solid biomass can be combusted for process heat or power generation, or gasified to produce synthetic fuels. Biogas sources can be processed in anaerobic digestors into biogas (a mixture mostly of methane and carbon dioxide, assumed in the model to be 60% methane and 40% carbon dioxide by volume). The boundary is fluid; some solid biomass could be used in biogas units (for example, Millinger et al, 2025 also allow straw to be mixed into the biogas substrate).

For the European area using wastes and residues from the JRC's ENSPRESO dataset (medium potential) this translates in 2030 to 1049 TWh/a of solid biomass (coming from agricultural residues like straw, forestry residues, sawdust, biogenic municipal waste) and ~342 TWh/a of biogas (from animal manure and sludge waste).

Focusing on Germany, there is 189 TWh/a solid biomass and 32 TWh/a biogas.

Further sustainable biomass could be leveraged without increasing land usage by allowing to use cover crops (crops planted between growing seasons to maintain soil integrity) or grasses on marginal lands.

In the minimal methanol scenario, the 1391 TWh/a of biomass contains around 114 MtC/a (equivalent to 417 tCO₂/a).

1211 TWh/a of this is used to make methanol (99 MtC/a, 363 MtCO₂/a).

The rest goes to industry heat, where some carbon is captured.

Extra carbon is also captured from the Allam cycle plants, waste-to-energy plants and industry heat with carbon capture (? MtC/a, ? MtCO₂/a).

1500 TWh/a of methanol is produced (the extra energy coming from electricity and 648 TWh/a of hydrogen), which has 102 MtC/a (372 MtCO₂/a).

This carbon is then released into the atmosphere when used in planes and ships. Some carbon is captured from methanol use in Allam cycle plants, burning the resulting plastics from MtO/A in waste-to-energy plants and industry heat.

TODO: Sankey of carbon.

Most of the biofuels today come from dedicated energy crops that require significant amounts of energy, fertiliser and land. Including the indirect land use change that comes when food crops are displaced, forcing food to be grown on virgin land elsewhere, can make the life cycle greenhouse gas balance of some biofuels worse than fossil gasoline or diesel.

There are some limited biogenic wastes that could use routes other than methanol, e.g. used cooking oil via the HVO route to diesel or kerosene.

Research on life cycle emissions of biofuels:

• Searchinger et al, 2008: "Use of U.S. Croplands for Biofuels Increases Greenhouse Gases Through Emissions from Land-Use Change"
• Lark et al, 2022: "Environmental outcomes of the US Renewable Fuel Standard": "the carbon intensity of corn ethanol produced under the RFS is no less than gasoline and likely at least 24% higher"

Recent fraud concerns:

• Euractiv 2024: Discrepancy in British and Irish used cooking oil imports raises biofuel fraud concerns "A new analysis suggests more Malaysian used cooking oil was exported to Britain and Ireland than was collected in the country, raising fears that banned substances are being fraudulently passed off as the in-demand biofuel feedstock."
• BBC 2019: Used cooking oil imports may fuel deforestation
• Tagesschau 2025: Von falschen Klimazertifikaten und Palmölschwindel

There have been several recent scandals with palm oil being incorrectly relabeled as used cooking oil, as well as fraud in the German GHG certificate scheme (see above), among many other cases of fraud.

The scientific view on lifecycle greenhouse gas emissions can also change over time as new data and methods become available.

One way to enhance the credibility of sustainability assessments would be to establish an independent scientific committee to regularly review the emissions factors assigned to different feedstocks.

Another way to raise credibility would be to only allow local wastes and residues to be used, i.e. avoid reliance on imported fuels, so that confidence in regulation is raised.

Producing methane instead of methanol would allow more of current fossil gas demand to be directly replaced, and would reuse more of the existing methane infrastructure (pipelines, storage, end-use devices).

We would argue that:

• Future methanol demand is much more robust than methane demand in climate neutral scenarios.
• Many sources of biomethane, such as biogas plants, are not close enough to the current methane pipeline network to connect in a cost-effective way.
• As methane demand reduces, it becomes harder to maintain much of the methane infrastructure.
• Methane is a greenhouse gas with around 28 times the global warming potential over 100 years (GWP100) of CO₂. Any leakage would contribute towards global warming.

Demand: The current methane demand mostly disppears in climate-neutral scenarios. Gas boilers for building heating are replaced by heat pumps; electricity generation from gas shrinks substantially; gas for non-energy use is replaced by hydrogen; gas for process heat is replaced by electrification, hydrogen and its derivatives.

Methanol is required, since it needed for high value chemicals (HVC), as a shipping fuel, and can also be used to make kerosene. These use cases make up 300-600 TWh/a each for Europe.

E-biomethanol would likely be cheaper to use in shipping than e-biomethane, as shown in the paper An assessment of decarbonisation pathways for intercontinental deep-sea shipping using power-to-X fuels (2024).

The logistic costs of liquefied methane (LCH₄) are simply higher than methanol, which is already liquid.

Pipeline proximity: As discussed in the blogpost What flexibility do we need from biogas?, in Matschoss et al, 2020 IZES and UFZ authors found that only 22% of today's biogas plants in Germany by kW output would be eligible for upgrading, even before further economic analysis.

Uncertainty around future methane infrastructure: As building heating and other demands reduce, much of the distribution network for methane could be retired. This makes it still harder to connect biomethane producers.

Some biomethane is liquefied already today for use by trucks. LCH₄ could also be produced decentrally and brought to larger gas pipelines, to mitigate some of the issues of missing gas distribution.

For an idea what this might look like, see the Swedish paper Gustafsson, 2024 (Sweden has a limited gas grid; upgrading can be done cryogenically to match LCH₄ temp).

However, we reiterate the point that future methane demand is expected to be small in climate neutral scenarios. Trucking is electrified, and for shipping methanol is a superior fuel to LCH₄.

The costs of maintaining the existing high pressure transmission network are very low when distributed over today's high consumption. However, with the lower methane demand of a climate neutral scenario, the specific costs per transported MWh would rise.

In addition, the distribution network costs to bring (e-)biomethane to it, and from it to the small number of users, could be quite high.

In general the production costs of e-biomethanol are expected to be somewhat higher at ~180 EUR₂₀₂₀/MWh compared to ~100-120 EUR₂₀₂₀/MWh for e-hydrogen and ~120-150 EUR₂₀₂₀/MWh for e-biomethane beyond the year 2030. However, the costs of transporting and storing the hydrogen and methane are expected to be much higher than for methanol.

For example, consider the usage case of a hydrogen power plant running 500 hours per year paying a 25 EUR/kW/a network fee for peak demand (suggested by the German Federal Network Agency for the ramp-up of the German core hydrogen network). This translates to 25000 EUR/MW/a / 500 h/a = 50 EUR/MWh, which already closes the gap with methanol. Add in the costs for storing the hydrogen, and the cost advantage disappears.

Industry demand with constant hydrogen usage would pay a much lower network fee per MWh, and would see lower costs for hydrogen.

Methanol can be transported flexibly by truck, barge, ship, train or pipeline.

For large volumes pipelines are most efficient. Liquid fuels like crude oil and well as refined products like diesel, gasoline and kerosene are transported by pipeline today.

Methanol could reuse some of this pipeline infrastructure.

Liquid product transport by pipeline is considered to be easier to build, since the pipelines have a smaller diameter and don't offer the same dangers of explosion as hydrogen or asphixiation in the case of carbon dioxide.

In the default scenarios we assume the availability of a CO₂ pipeline to transport process emissions from industrial sites and biogenic CO₂ to sequestration sites offshore as well as for fuel synthesis.

CO₂ is transported by pipeline in a supercritical state cooled and under pressure as a liquid, so that the pipelines can have a narrow diameter. If the pipelines are not well regulated, accidents can be a threat to health (a pipeline accident in 2020 in Mississippi sent 45 to hospital, although this may have been due to hydrogen sulfide mixed in).

In an sensitivity calculation the removal of the CO₂ pipeline raised costs by 2% (forcing more biomass to be used for CDR to compensate industry process emissions that cannot be transported to sequestration sites):

See also Hofmann et al, 2025 on the cost benefits of CO₂ pipeline networks.

Yes, solid biomass transport by truck is costed at 0.1 EUR/MWh/km (based on JRC-EU-TIMES). For biogas distribution via pipelines, costs are around 7 EUR/MWh for a 10 km distance (based on Gustafsson, 2024).

The minimal methanol scenario was around 24 billion euros per year (3%) more expensive than the cost-optimal scenario.

The main cost drivers are:

• Methanol (~180 €/MWh) itself is more expensive than fossil gas compensated by carbon dioxide removal (~30 €/MWh + ~40 €/MWh) or electrolytic hydrogen (~100 €/MWh) because of the further conversion steps. Therefore whereever methanol is substituting methane or hydrogen, it is increasing costs. An extra cost of 100 €/MWh on 250 TWh/a for backup power and heat makes 25 billion euros per year.
• Decentral biomass boilers, allowed in the other scenarios, must be replaced by heat pumps in the "minimal methanol" scenario.

Yes, methanol tanks next to power stations is resilient against attacks on infrastructure.

Black-start-capable power plants follow this strategy: fuel oil bunkered next to diesel generators to restart the grid after a black out.

A similar strategy is followed in regions with unreliable power supply, where diesel generators are used for backup power supplies.

The Allam cycle generator uses pure oxygen to combust the fuel, allowing a pure stream of carbon dioxide to be captured from the exhaust. This reduces the energy requirements and costs for carbon capture. The use of the Allam cycle was explored in a previous paper with a toy model of the power sector.

However, once the concept is expanded to the full energy system like in the current paper, biogenic sources can be used for the methanol and the need to cycle carbon dioxide by capturing it is much reduced.

The model only builts 20 GW of Allam cycle running with full load hours of 1350. Costs would barely increase if the Allam cycle was disallowed and the model was forced to use CCGT instead.

The reason: the low running hours of the backup power plants tend to lead to low-capex solutions. Carbon capture is relatively high-capex.

The Allam cycle has seen recent delays and cost escalations in deployment, so it may be best to plan without it.

Retrofitting gas turbines from methane to use methanol is relatively simple and substantially easier than retrofitting for hotter-burning hydrogen. Burners and fuel delivery must be changed, and mass flow adjusted. Since methanol burns at a lower temperature than methane, it reduces the formation of unwanted NO_x emissions.

A gas turbine in Israel was already converted to methanol to meet strict NO_x and other emission standards.

The Siemens gas turbine SGT-400 is sold as running on methanol.

See also the Methanol Institute's power generation page.

Both methanol synthesis and gasification need to take place at double-digit-MW scale to benefit from lower specific costs. Unlike other components that are linear beyond MW-scale (electrolysis, PV, batteries, biogas plants, biogas upgrading), they benefit from these large economies of scale.

Literature indicates that the production size should be at least 25 MW_MeOH or around 35 kt_MeOH/a when operating for 8000 hours per year.

Ideally for lower costs it should be more like 100-200 kt_MeOH/a, i.e. 75-150 MW_MeOH.

For Europe's 1500 TWh_MeOH/a demand, this would be around 2300 plants of capacity 75 MW_MeOH, or 1150 plants of size 150 MW_MeOH. (Comparison: there are more than 10,000 biogas plants, over 200 biorefineries for biofuels and 90 oil refineries in Europe.)

For German needs of 200 TWh_MeOH/a this would be around 330 plants of capacity 75 MW_MeOH. (Comparison: there are around 10,000 biogas plants in Germany today.)

Assuming residues were collected from 170,000 km² of agricultural land in Germany, each plant would have a catchment area of around 500 km², i.e. a radius of around 13 km. Whether biomass is transported to a central processing plant, or processed to biogas or biocrude decentrally before transport, is open to optimisation.

Example of small biogas networks aggregating:

Depending on the mixture of available substrates, either biogas or gasification units or both could serve each methanol synthesis unit.

Gasification plants benefit from the same economies of scale as the methanol synthesis. For the cost assumptions the model uses from the Danish Energy Agency's Renewable Fuels Technology Catalogue it is assumed than the gasification to methanol plant has a scale of 200 kt_MeOH/a by 2030.

200 kt_MeOH/a production capacity corresponds to 550 t_MeOH/d, which could be transported away by 22 truck trips per day carrying 25 t_MeOH each.

Multiple methanol plants could be aggregated to a multi-Mt_MeOH/a pipeline.

There are many pipelines today for crude oil as well as refined products like gasoline, diesel and kerosene.

Many existing biogas plants are smaller than the scale needed for methanol synthesis. However, several small plants could be linked up together in a local biogas pipeline network to feed a single synthesis unit. There are examples of small biogas pipeline networks in Germany today.

The default scenarios in the paper allowed 200 MtCO₂/a sequestration in offshore saline aquifers and depleted oil and gas fields. This is enough to sequester all industry process emissions as well as some carbon dioxide removal (CDR).

Comparable studies have similar assumptions. The CCS-friendly CATF included at most around 300 MtCO₂/a in their scenario for Europe for 2050. The EU Commission's Carbon Management Strategy has around 250 MtCO₂/a in 2050.

To explore the dependence on sequestration volume, we varied it in two sensitivities with 400 and 600 MtCO₂/a. Since using fossil fuels and compensating with CDR from bioenergy with CCS (BECCS) is generally cheaper than CCU, the scenarios are lower cost.

At 400 MtCO₂/a the use of methanol for HVC (MtA/O) and kerosene is reduced; methanolisation reduces to compensate:

At 600 MtCO₂/a the main use is in shipping; methanol is still made from biogas with a little extra from solid biomass:

In principle it is cheaper to sequester a tonne of biogenic CO₂ to compensate for a tonne of fossil fuel use than to use it in a synthetic fuel. If the transport and sequestration costs 100 EUR/tCO₂, the abatement cost could be around 150 EUR/tCO₂, while for the synthetic fuel it could be 300-400 EUR/tCO2.

However, as discussed above, the sequestration volume per year is expected to be much lower (200-300 MtCO₂/a) than that need to compensate all shipping and aviation emissions with CDR (500-700 MtCO₂/a). This is because of the need to expand the rate (in MtCO₂/a) in time for 2050, rather than a limit on the total of CO₂ that can be stored offshore (which could be as high as 100 GtCO₂).

Furthermore, upstream emissions from fossil fuel usage must also be compensated, along with the higher contrail formation with fossil fuels.

Furthermore, transporting CO₂ from many decentral biomass sources would require pipelines and trucks. CO₂ transport is likely to have lower acceptance than methanol, since CO₂ is an asphyxiating gas.

The carbon dioxide abatement cost, measured as the shadow price of the constraint setting carbon dioxide emissions to net-zero, varies depending on the scenario. If we stick with the methanol economy and keep the sequestration limit tight (200 MtCO2/a), it's 426 €/tCO2, if we relax to 400 MtCO2/a it drops to 335 €/tCO2, then at 600 MtCO2/a it's just 124 €/tCO2. As sequestration is relaxed, CCU is replaced by fossil+CDR. That last value is quite low because the model is forbidden in that scenario from using fossil gas as a gas. If fossil gas allowed with 600 MtCO2/a sequestration, the price rises to 239 €/tCO2, since that's cheaper than making fossil methanol.

See BlueSky discussion.

Very few. Plants can be flexibly repurposed for e-biomethane or for biomethane/ol with carbon dioxide removal for the excess CO₂.

Some infrastructures would be in common: collection logistics for biomass, use of syngas for methane/methanol synthesis.

The Kasso e-methanol plant in Denmark is the largest, using CO₂ from a nearby biogas plant. Plants in China too are being built (although CO₂ source needs to be checked).

Hanno Böck's Feb 2025 summary of active e-biomethanol projects

Shipping companies like Maersk are already signing offtake agreements for green methanol for their ships. Customers for the Kasso plant include Maersk, Novo Nordisk and Lego.

A large fraction of industrial process heat is electrified in the model, following the 2035 potentials in Agora's 2024 study on industrial process heat electrification. Existing biomass uses, such as in the pulp and paper industry, are left as they are. Methanol is used for the flat glass industry, although it is not as good at providing radiant heat as methane (ironically due to methane's unclean burning compared to methanol).

Yes, methanol usage for shipping, producing kerosene and high value chemicals (HVC) is prefered in the model over alternatives (other fuels for shipping (although model isn't offered full pallette), Fischer-Tropsch for kerosene and naphtha for HVC).

The main differences between the scenarios is the use of fuels for backup electricity and heat.

In the paper the import of green methanol from outside of Europe was only allowed in the scnario "green imports" along with imports of green steel and green ammonia:

This reduces the cost of the minimal methanol economy scenario by 26 bnEUR/a (3%), see Panel A.

In the minimal methanol scenario, 619 TWh/a of 1550 TWh/a total methanol is imported:

Hydrogen production in Europe is much lower than in the default scenario.

Since the sustainability of carbon sources abroad cannot be guaranteed, it was assumed that direct air capture was used to source the carbon dioxide. This makes the methanol more expensive. Some sites in Europe can compete with these imports, because they have both biogenic carbon dioxide and cheap hydrogen.

There has been significant fraud with the sustainability criteria of imported biofuels (see discussion of biofuels above), so this would have to be carefully regulated.

Since biogenic wastes and residues are limited worldwide, it might make sense for Europe to cultivate its own biogenic biomass to maximise supply.

The following innovations would improve the case for a minimal methanol economy:

• Methanol catalysts that would allow more flexible operation, allowing the synthesis to shut down during periods of low wind and solar.
• Methanol catalysts that work at lower pressures and temperatures, allowing smaller less complicated synthesis units, like the novel homogeneous liquid catalyst from carbon.one.
• Plant breeding or genetic engineering to improve the fuel yield of the biomass substrates.
• Improvements and cost reductions to solid oxide electrolysers that allow heat integration with methanol synthesis, and possible reverse operation as fuel cells.

The following innovations in competing technologies would worsen the case for a minimal methanol economy:

• Cheap and plentiful carbon dioxide removal options (e.g. burying biomass, innovations in carbon sequestration).
• Improvements to synthesis of competing liquid fuels, e.g. ethanol, DME or Fischer-Tropsch.
• Electrification concepts for long-haul aviation or shipping.
• Onboard carbon capture on ships (although this could work with the methanol economy).
• Increase in plastic landfilling, which would act like carbon sequestration and reduce the need for primary green HVC.

These technologies would allow methanol use to further be minimised. A "minimal methanol" economy can also be a "no methanol" economy.

The fact that methanol does not rely on complex interlinked infrastructure, allows methanol production targets to be easily adjusted downwards, unlike hydrogen, that needs complex coordination of pipelines and underground storage.

Methane is a greenhouse gas with around 28 times the global warming potential over 100 years (GWP100) of CO₂. Hydrogen is an indirect greenhouse gas (it prolongs the life of methane in the atmosphere) with a GWP100 of 11.6 ± 2.8 (Sand et al, 2023). Any leakage of methane or hydrogen could weaken the case for these energy carriers.

Methane leakage from extraction, transport and storage can be as high as 5% or more across the value chain (Weller et al, 2020). However, producers such as Norway have managed to regulate leakage successful to keep it below 1%.

Biogas production is one source of carbon in the minimal methanol concept, so would also have to be regulated carefully.

TODO: 2025 paper: Assessing hydrogen supply chains: An integrated review of leakage and energy efficiency studies: "gaseous H₂ systems have ∼4.5% leakage"

Compare: VDE: The Cellular Approach.

Some similarity, in that a 100-200 kt_MeOH/a synthesis plant with a biomass collection area of 500-1000 km² determines a cellular structure.

See Taslimi & Khosravi, 2025 for Kasso plant: electrolyser operates 75-80% capacity factor; shutdowns can be minimised; hydrogen is buffered in storage; methanol synthesis runs with 90-95% capacity factor.

The careful collection and processing of biomass wastes and residues, primarily from agriculture and forestry, put agriculture and forestry at the centre of the "minimal methanol" economy. Whether down a CCU or CDR route, sustainable biogenic CO₂ takes centre stage.

Coordinating carbon management with food production, to avoid indirect land use from fuels, becomes very important.

Methanol production would provide a more stable, climate-friendly and higher income level than current biofuels or biogas production.

Let's run through the use cases of methanol that could incorporate CO₂ capture:

• Aviation: Many technical challenges here; could power electric motors with fuel cells equipped with CO₂ capture, but CO₂ itself would be too heavy and bulky to transport.
• Shipping: Here there are several concepts to allow onboard capture and unload liquid CO₂ at port.
• Waste-to-energy plants: WtE plants with carbon capture are already included in the model; they run baseload to process waste that cannot be landfilled.
• Peaking power plants: As discussed above in relation to the Allam cycle, carbon capture is CAPEX-intensive and doesn't match the economics of plants that run for just a few hundred hours a year (which are generally low-CAPEX, high-OPEX, see screening curve analysis).

Mitsui and Mitsubishi are working on a ship than would transport LCO₂ to a methanol production site and transport methanol back.

The volumes of liquid would match well (1 MWh of methanol has a volume of 0.23 m³ and requires 0.248 tCO₂ with a liquid volume of 0.23 m³), but the CO₂ is 38% more massive. The CO₂ also needs to be cooled and transported under pressure.

Steel and ammonia are produced using local hydrogen production in the "minimal methanol" scenario.

If existing sites in Europe for steel and ammonia are used, these are sub-optimal for hydrogen production, so the model transport some methanol to these sites for steam-reforming back into hydrogen.

If steel and ammonia can relocate within Europe (scenario "relocation") then they move to good H2 sites and the model avoids steam-reforming methanol:

Here are the relevant sections from our 2025 paper The Minimal Methanol Economy as a Gap-Filler for High Electrification Scenarios that discuss alternative energy carriers.