Why Small Hydrogen Markets Are Likely to Shrink

March 06, 2026

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by Michael Barnard (Clean Technica) Someone recently asked me about small, distributed hydrogen use cases and whether those markets might eventually be served by imported green methanol cracked onsite to produce hydrogen. The idea is not irrational. Hydrogen is difficult to transport and store. Methanol is a liquid fuel with existing global shipping infrastructure. Catalytic methanol cracking can produce hydrogen and carbon monoxide at the point of use. If a factory needs hydrogen, perhaps importing methanol and cracking it locally would provide a simple pathway to decarbonized hydrogen supply. The question prompted me to review the literature on smaller hydrogen markets because the scale and durability of those markets determine whether such a supply chain would ever make economic sense.

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Oil refining and ammonia production dominate hydrogen consumption. The other categories are much smaller. When thinking about future hydrogen demand, the key question is whether those smaller uses grow or shrink as the century progresses.

A factor shaping the future of hydrogen demand is that hydrogen production today is itself a major climate problem. Almost all hydrogen is produced from fossil fuels, primarily through steam methane reforming of natural gas and coal gasification. These processes convert hydrocarbons into hydrogen while releasing large amounts of carbon dioxide as a byproduct.

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Before hydrogen can be considered a climate solution in any new application, the existing production system has to be decarbonized. That places the priority on replacing fossil based hydrogen in large industrial uses such as refining, ammonia production, and methanol synthesis rather than expanding hydrogen consumption into new markets.

The largest structural change in hydrogen demand will occur in oil refining. Hydrogen is required to remove sulfur and other impurities from petroleum products. It is also required to crack heavy hydrocarbon molecules into lighter fuels. These processes consume large quantities of hydrogen, but the amount required depends heavily on crude oil quality.

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Ammonia production is the other major hydrogen consumer. Hydrogen is combined with nitrogen through the Haber Bosch process to produce ammonia for fertilizer.

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Many decarbonization scenarios assume that hydrogen demand will grow because ammonia production will shift from natural gas derived hydrogen to electrolytic hydrogen produced from renewable electricity. That assumption deserves scrutiny.

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Green ammonia represents decarbonization of an existing hydrogen market rather than guaranteed expansion of it.

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Steel production is often cited as another major future hydrogen market. Hydrogen-based direct reduced iron processes are promoted as a pathway to green steel. However hydrogen direct reduction is only one option among several competing technologies. Electric arc furnaces using scrap steel already produce about 30% of global steel. That share can grow as recycling systems improve. Boston Metal’s molten oxide electrolysis, Fortescue’s electrochemical ironmaking processes, flash ironmaking, biochar blast furnace ironmaking, and biomethane-fueled direct reduction offer alternative pathways that do not rely on hydrogen as a primary reducing agent.

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Hydrogenation includes chemical processes where hydrogen is added to organic molecules, such as in food processing, pharmaceuticals, and biofuel upgrading.

Mixed other includes a wide range of industrial uses. These include metal annealing atmospheres, specialty metallurgy, electronics manufacturing, and various small scale chemical reactions. These uses are often geographically distributed and operate at relatively small scale. They are the markets that the methanol cracking proposal would theoretically serve.

Reviewing the literature reveals several consistent characteristics of these small hydrogen markets. The first is scale. Many facilities consume hydrogen in quantities measured in kilograms or tens of kilograms per day. Occasionally consumption reaches hundreds of kilograms per day. These facilities rarely produce hydrogen themselves. Instead they purchase hydrogen from industrial gas suppliers.

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If low carbon hydrogen produced through electrolysis or carbon capture pathways costs three to five times more than conventional hydrogen from natural gas, the price signal reaches small users quickly.

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The third characteristic is the availability of substitutes. Several industrial processes historically using hydrogen now operate with alternative technologies.

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Hydrogen leakage introduces another factor influencing these markets. Hydrogen is now understood to be an indirect greenhouse gas. When released into the atmosphere hydrogen reacts with hydroxyl radicals, reducing the atmosphere’s ability to break down methane. This interaction increases methane lifetime and contributes to warming.

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The green methanol cracking proposal must be evaluated in this context. Methanol can be produced from biomass and transported globally using existing shipping infrastructure. Catalytic reactors can decompose methanol into hydrogen and carbon monoxide. Installing such reactors at industrial facilities could in theory provide on site hydrogen supply without relying on compressed hydrogen deliveries. However the economics depend on scale. A facility consuming 20 kg of hydrogen per day would require a relatively small reactor but would still face capital costs, maintenance requirements, and operational oversight. For many facilities the simplest solution remains purchasing more expensive low-carbon hydrogen from industrial gas suppliers or avoiding hydrogen entirely.

What most firms will actually do is straightforward. Some will substitute alternative processes that eliminate hydrogen use. Some will reduce hydrogen consumption through recycling or process optimization. Others will continue purchasing hydrogen from industrial gas suppliers and allow those suppliers to manage regulatory compliance and infrastructure. Installing methanol cracking equipment will make sense in some cases, particularly where hydrogen consumption is larger and steady. In many other cases the complexity outweighs the benefits.

Biofuel processing deserves a brief proviso because it represents the only segment of hydrogenation that I expect to plausibly grow. Hydrotreated vegetable oil and sustainable aviation fuel pathways consume hydrogen during hydrodeoxygenation reactions that remove oxygen from bio based feedstocks. These processes can require tens of kilograms of hydrogen per ton of feedstock. Transfer hydrogenation methods cannot easily replace these reactions at industrial scale because the hydrogen donor molecules would need to be regenerated, reintroducing the hydrogen supply requirement.

Other biofuel pathways such as alcohol to jet or methanol to jet may require less hydrogen, but hydrogen demand in biofuel upgrading will not disappear entirely. For that reason hydrogenation in biofuel processing remains a possible growth area, although its ultimate scale depends on which sustainable aviation fuel technologies dominate.

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Across my analysis over the past several years I have consistently found that hydrogen is poorly suited to become a broad energy carrier because it performs badly when compared with direct electrification and biological fuels on efficiency, cost, and system complexity. Converting electricity into hydrogen through electrolysis, compressing or liquefying it, transporting it, storing it, and then converting it back into electricity or mechanical work wastes a large share of the original energy. Battery electric systems typically deliver 70% to 90% of input electricity to useful work, while hydrogen pathways often deliver closer to 30% to 40% once production, compression, distribution, and fuel cell conversion losses are included. Hydrogen infrastructure also requires expensive compression equipment, specialized pipelines, storage systems, and strict safety management. In most sectors direct grid connections, batteries, and biofuels provide simpler and more efficient solutions.

Hydrogen is also a poor solution for seasonal energy storage when compared with simpler options that already exist.

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The second is maintaining existing gas generation assets as strategic reserves fueled by biomethane stored in the natural gas infrastructure we already have. Biomethane can sit in underground gas storage for months or years and be burned in existing gas turbines during rare dunkelflaute events when wind and solar output fall for extended periods. This approach avoids building entirely new hydrogen infrastructure while using assets that already exist, providing reliability at far lower cost and complexity.

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Electrification technologies already exist for most commercial and industrial heating applications, leaving little room for hydrogen outside a narrow set of specific chemical processes that like flames, and even there biomethane is a cheaper alternative.

That’s why my projection has no hydrogen for transportation, energy storage or heating applications. Where an alternative to hydrogen exists, it is usually cheaper and simpler. Hydrogen handling requires specialized equipment, safety protocols, and regulatory oversight. That is why hydrogen has not become a widespread energy carrier despite decades of experimentation. It remains valuable where its chemistry is required, but many applications historically using hydrogen have already found alternatives. As hydrogen production decarbonizes and costs rise, that substitution trend will continue. READ MORE