Client€8B Global Industrial Machinery Company
SprintA 6 week sprint
Fieldwork3 countries · 7 expert interviews · 3 demand scenarios modelled
Strategy and Commercial Excellence
Seventy six plants, seven of them running
An equipment maker wanted to know where biofuel regulation across Asia Pacific would create demand for its technology. The announced project pipeline in the largest market looks enormous. Counted by what is actually operating, it is seven plants and about two per cent of the announced capacity. The gap between those two numbers is where the commercial judgement sits.
76
Biomethanol plants announced in the largest market
7
Of them operating, at 345 kt of capacity
3%
Utilisation of the existing methanol capable fleet today
€650 to 1,753
Capital cost per tonne, on expert estimates
A note on sourcing. Every figure here comes from a SprintlyWorks client engagement. Clients are described, never named. Where a figure is identified, modelled or indicative rather than banked, the line says so.
01
The pipeline is not the market
Three countries were mapped: the regulatory framework, the forecast blending mandates, and what both imply for equipment demand. The headline numbers are spectacular. Renewable methanol capacity across the three is projected to rise from about half a million tonnes to more than thirty million by 2030, at a growth rate above a hundred per cent a year on third party projections.
Broken down by development stage, the picture changes. In the largest market, 58 of the announced plants are at feasibility or pre feasibility, three are in engineering and eight are under construction. Seven are operating, at 345 thousand tonnes between them, averaging 49 thousand tonnes each against a 240 thousand tonne average for the announced ones.
Announced capacity is a signal of intent. It is not a market, and for a company selling process equipment the difference between the two decides where the sales effort goes.
The pipeline
Announced capacity against operating capacity
Biomethanol plants in the largest market in scope, by development stage. Third party project pipeline data, not built capacity, and the last row is the only one that exists today.
| Stage | Capacity | Plants | Average per plant |
|---|---|---|---|
| Feasibility or pre feasibility | 13,970 kt | 58 | 241 kt |
| Under construction | 1,907 kt | 8 | 238 kt |
| Engineering | 780 kt | 3 | 260 kt |
| Operating | 345 kt | 7 | 49 kt |
How to read this → The operating plants are a fifth the size of the announced ones. Whatever gets built will probably be smaller than what was announced.
SprintlyWorks analysis
02
Demand was modelled, and the assumptions are the model
Maritime biomethanol demand was built in four steps: methanol capable fleet capacity from published vessel data, a utilisation rate assumption, the two multiplied to give low carbon methanol demand, then an assumption that half of that demand is biomethanol and half is other low carbon methanol.
Three scenarios were run against international decarbonisation pathways, giving a 2050 range of roughly 19 to 34 million tonnes. Every one of those figures is a projection resting on the utilisation and share assumptions above, and the page says so rather than quoting the midpoint as fact.
The most useful number in the whole exercise is the smallest. Ships already able to burn methanol could take about three million tonnes a year. Less than a tenth of a million tonnes was actually bunkered. Utilisation of the existing capable fleet is around three per cent, which is a better guide to the pace of this transition than any 2050 curve.
03
What it costs to build one
Capital cost estimates from three plant operators ranged from about €650 to €1,750 per tonne of annual capacity, against a published reference range that runs considerably higher. Core process equipment is about three quarters of the total, split across gasification, feedstock pre treatment, purification, synthesis and distillation.
Operating cost ran roughly €270 to €620 per tonne, and it is dominated by two lines. Feedstock plus its logistics and pre processing is 35 to 70 per cent depending on the operator. Energy is 15 to 45 per cent. Labour and maintenance is around a tenth.
One operator noted that capital cost rises by about 60 per cent rather than proportionally when capacity is multiplied, which is the scale argument in a single sentence. Another noted that operating cost in the western and northern regions runs 10 to 15 per cent below elsewhere, which is the location argument in another.
04
The near term pull is not the exciting one
Biomethanol as a marine fuel is the story with the growth curve attached. The demand that exists now is in biodiesel production, where methanol is a process input rather than a fuel, and where biomethanol is chemically identical to the fossil version so it drops straight in with no plant change.
The obstacle there is arithmetic, not technology. Methanol is about a tenth of the cost of making biodiesel and feedstock is three quarters. Biodiesel margins are thin, biomethanol costs more than fossil methanol, and no regulation requires the switch. Without a customer pulling, nobody pays more for an input that makes no difference to the product.
That is why the first recommendation was to go and test willingness to switch rather than to build a sales campaign. The technical barrier is zero and the commercial barrier is complete, and only the customer can say what would move it.
05
Where the regulation actually helps
The three countries pull in different directions, and the route to market differs by both country and transport mode. In the largest, policy support already spans capital grants, production support and bunkering, and methanol has an existing road fuel channel at high blends. In another, biodiesel is policy led through a national blending mandate that stepped up at the start of the year, while biomethanol sits outside the mandate entirely and has to be sold project by project. In the third, biomethanol is not a standard road fuel at all and biodiesel is accepted only at low blends.
The practical constraint named repeatedly is not the fuel rule. It is port permitting, which is where a bunkering project stalls.
A separate comparison put the permitting difference plainly: projects of this kind in Europe often run five to ten years end to end because the upstream renewable power and grid connections are slow, against roughly two to three years in the largest market in scope. That slide is marked preliminary research and the figures are indicative.
06
What the client was left holding
A country by country regulatory map, a modelled demand forecast with its three scenarios and their assumptions exposed, a cost picture built from operators rather than from published averages, and a sales toolkit for the customer conversations.
Three next steps, in order. Test whether biodiesel and chemical producers would actually switch to biomethanol from fossil methanol. Benchmark the client own technology against the competing gasification routes. Then identify the customers to position it with.
The order matters, and it is the honest one. There is no measured result in this work. No equipment was sold and no plant was won. What it produced was a reason not to build a sales campaign on a pipeline that is 58 plants of paper and seven plants of steel.
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