Green Ammonia

Ammonia is the second most produced chemical in the world by mass, with around 180 to 200 million tonnes manufactured each year. Roughly 80 percent of that volume goes into nitrogen fertiliser, which underpins about half of the food produced globally. The process that makes it, Haber-Bosch, has been called the most important invention of the twentieth century, and not without reason. Fritz Haber's 1909 demonstration and Carl Bosch's subsequent industrialisation gave humanity the ability to fix atmospheric nitrogen at scale, breaking the agricultural ceiling that had constrained the planet's population for millennia.

A century later, Haber-Bosch is also responsible for roughly 1.3 percent of global CO₂ emissions. That is more than the entire economy of Germany. Almost all of it comes from one source: the steam methane reforming step that produces the hydrogen feedstock. The Haber-Bosch reaction itself is unavoidable if you want ammonia. The hydrogen, however, does not have to come from natural gas.

This is the central appeal of green ammonia. Unlike many proposed decarbonisation pathways, there is no demand-creation problem to solve. The market exists, at industrial scale, with existing infrastructure, existing transport networks, and existing customers. The challenge is purely on the supply side: producing the hydrogen feedstock from electrolysis rather than methane reforming, while keeping the rest of the plant running.

Haber-Bosch was designed for continuous, baseload operation. The catalysts need to stay hot. The recycle compressors need to keep running. The synthesis loop is a tightly coupled thermodynamic system that does not enjoy being switched on and off. A conventional ammonia plant runs continuously for years between maintenance shutdowns, and the entire engineering of the plant assumes this.

Coupling this assumption with intermittent renewable electricity is the central engineering challenge of green ammonia, and the place where most early projects underestimate the complexity.

Three families of solutions exist. Real projects almost always use some combination of all three.

Buffer storage between the electrolyzer and Haber-Bosch. A compressed hydrogen storage tank, sized to bridge typical periods of low renewable generation, smooths the supply to the synthesis loop. The downside is capital cost. Hydrogen storage at scale is expensive, and sizing it correctly involves real engineering judgement about how variable the upstream supply will actually be. A storage tank sized for the average bad week is a different beast from one sized for the average bad day.

Hybrid power supply. A combination of dedicated renewable electricity, grid imports during low-renewable periods, and in some cases biomass-derived or nuclear power, can provide a steadier electrolyzer load. This trades off cost against the strictness of any renewable hydrogen certification. RED III rules in Europe, in particular, place real constraints on how much grid electricity can be counted as renewable for the purposes of the certification.

Flexible synthesis loop design. Engineering the Haber-Bosch plant itself to tolerate meaningful turn-down and load variation requires modifications across the catalyst bed, the recycle compression, and the cooling system. Several vendors now offer "dynamic" or "flexible" ammonia synthesis trains designed for 30 to 100 percent operating range. They cost more than a conventional plant per tonne of installed capacity, and their economic case depends on the price spread between baseload and variable electricity at the project site.

A fourth pathway is more speculative but worth tracking. Novel synthesis routes that bypass Haber-Bosch entirely, including electrochemical ammonia synthesis (producing NH₃ directly from N₂, water, and electricity in a single electrochemical cell) and plasma-assisted ammonia synthesis, promise inherent compatibility with variable renewables. They sit at TRL 4 to 6, with research-scale demonstrations only. None is close to commercial deployment in 2026. They are worth understanding. They are not yet worth designing around.

The use cases for green ammonia are more clearly differentiated than the use cases for green hydrogen, partly because ammonia is harder to handle than hydrogen, and partly because it has fewer substitutes in its core markets.

Decarbonising existing ammonia demand. This is the no-regret application. Approximately 180 to 200 million tonnes of ammonia are produced annually, and almost all of it currently uses fossil-derived hydrogen. Fertiliser will not stop being needed; nitric acid and caprolactam plants will not switch to a different feedstock. The decarbonisation pathway is to change how the hydrogen is made, not what the downstream user consumes. This single application is approximately ten times larger than all proposed new use cases combined. It is where the economics work first, fastest, and most predictably.

Maritime fuel. Deep-sea shipping is one of the harder sectors to decarbonise. Batteries are not credible at the energy densities required for long voyages. Bio-LNG and bio-diesel are constrained by feedstock availability. Green ammonia offers an energy density of 12.7 MJ/kg and a much higher volumetric density than compressed hydrogen, both of which make it credible as a marine fuel. Major shipping operators including Maersk, MOL and NYK have begun ordering ammonia-fuelled or ammonia-ready vessels, and engine manufacturers including Wärtsilä and MAN Energy Solutions have ammonia-capable engines commercially available or in advanced development. The first commercial ammonia-fuelled vessels are entering service in 2024 and 2025. Marine fuel could plausibly grow into a 30 to 60 million tonne-per-year ammonia market by 2040, though it depends on continued regulatory pressure and the resolution of the safety and N₂O issues discussed below.

Power generation co-firing in East Asia. Japan and South Korea have national strategies that include ammonia co-firing in existing coal-fired power plants as a transition pathway. The Japanese utility JERA has demonstrated 20 percent ammonia co-firing in commercial coal plants, with plans to scale to 50 percent and eventually 100 percent. Outside East Asia, the case for ammonia in power generation is much weaker, because renewables plus battery storage offer better economics in OECD markets. Within East Asia, the existing coal fleet, the high cost of land for new renewables, and the policy choice to extend the operating life of existing plants gives ammonia a real near-term role in the decarbonisation pathway. Whether this remains true over the long term depends on how renewable costs evolve in those geographies.

Hydrogen carrier for long-distance trade. Ammonia is one of three serious candidates for moving green hydrogen across oceans, alongside liquefied hydrogen and liquid organic hydrogen carriers. Its advantage is the existing trade infrastructure: approximately 120 ports globally already handle ammonia, and a fleet of dedicated ammonia tankers exists. Its disadvantage is that if the ammonia must be cracked back to hydrogen at the destination, the round-trip energy penalty is substantial. Synthesis costs roughly 15 to 20 percent of the hydrogen's energy content. Cracking costs another 25 to 30 percent. For many proposed imports, the right first question is whether the destination really needs the hydrogen, or whether ammonia itself could be the end-product, used directly as fertiliser, marine fuel, or power co-firing feedstock. Where the destination can use ammonia directly, the carrier case is strong. Where it must crack, the case is weaker and the economics need to be examined carefully.

This is where ammonia's case as an energy carrier is genuinely strong, and where it compares favourably with the alternatives.

Ammonia is stored either as a liquid at -33°C and ambient pressure (refrigerated, the standard for large-scale storage) or as a liquid at around 10 to 15 bar and ambient temperature (pressurised, used in smaller installations). Both are mature technologies with decades of operating experience in the existing ammonia industry. Tank capacities of 50,000 tonnes and above are standard.

Long-distance transport is by dedicated ammonia tanker ships. The global fleet is comparatively small today (around 40 to 50 dedicated vessels), but the technology is mature and the fleet is expanding to meet projected demand. Approximately 120 ports worldwide handle ammonia, with most concentrated in fertiliser-importing regions and chemical hubs. The infrastructure is not as ubiquitous as that for LNG or oil, but it is real, operational, and considerably more developed than that for any other proposed hydrogen carrier.

Crucially, the energy penalty for storing and shipping ammonia is far lower than that for compressed or liquefied hydrogen. Ammonia is already a liquid at modest conditions. There is no continuous boil-off problem like liquid hydrogen, and there is no 700-bar high-pressure infrastructure requirement like compressed hydrogen.

The trade-off appears at the destination, if and when the ammonia needs to be cracked back to hydrogen. Cracking imposes a 25 to 30 percent energy penalty and requires temperatures of 400 to 700°C with appropriate catalysts. For destinations that can use ammonia directly (a fertiliser plant, a port bunkering operation, a co-firing power plant), there is no cracking penalty and the carrier case is strong. For destinations that genuinely need hydrogen at the end of the chain, the question to ask is whether shipping ammonia is actually the right answer, or whether the hydrogen should be produced closer to the user.