Skip to main content

From an ammonia roadmap to an ammonia society

Published by , Editorial Assistant
Global Hydrogen Review,

A new Memorandum of Understanding (MoU) has been signed by GE Gas Power and IHI to collaborate on the potential direct use of ammonia as a gas turbine fuel. Under the new MoU, GE and IHI are working to develop technology to use ammonia as a fuel, with the goal of using some of GE’s existing gas turbines to safely burn up to 100% ammonia by 2030, which can result in a significant reduction in carbon emissions from these gas turbines.

GE and IHI have studied the economics of utilising ammonia as a power generation fuel in Japan. Used abundantly as a fertilizer in agriculture, ammonia’s components, hydrogen and nitrogen, offer interesting potential as a zero-carbon fuel.

Taking the leap

Aiming to create a joint ammonia roadmap, GE and IHI are examining direct combustion of ammonia in a gas turbine to generate electricity, replacing natural gas. Transitioning to a new fuel goes beyond a reconfiguration of natural gas turbines, and impacts the broader ecosystem that surrounds them. This demands examination of the entire power plant to ensure that all systems are capable of supporting the use of ammonia. An ammonia roadmap could eventually lead to a broader vision, where hydrogen-carrying ammonia would become a way to store and deliver energy.

As part of the ammonia roadmap activities carried out under the companies’ first MoU, and to better understand the implications of this transition, GE and IHI conducted techno-economic studies on the use of ammonia as a power generation fuel. This research considered the use of ammonia as a carrier for energy. In this scenario, ammonia would be shipped to countries such as Japan, where it could be combusted directly in gas turbines as a fuel, or ‘cracked’ to provide hydrogen that could then be used in gas turbines in power plants. As with hydrogen, ammonia could also be used as a seasonal storage medium for the power sector, offering a potentially cheaper alternative to batteries.

As part of this work, the GE and IHI teams examined various low and zero-carbon fuel options for future electricity generation. The study considered the numerous process steps involved in the hydrogen and ammonia value stream, from hydrogen production to the end use application, which in this case is power generation. The value stream map (see Figure 1) includes production of hydrogen, production of ammonia, conversion, storage (at import/export terminals), marine transportation to Japan, and reconversion of ammonia back to hydrogen.

Figure 1. Hydrogen and ammonia value stream map used by GE and IHI as part of their joint study, which compared ammonia to the use of hydrogen and/or ammonia cracked back to hydrogen in Japan.

For comparison, an LNG and carbon capture, utilisation or storage (CCUS) solution was included in the study as the baseline, considering the cost of importing LNG and the cost of CCUS to cut the resulting greenhouse gas emissions. The social cost of carbon for both the LNG and LNG and carbon capture and sequestration (CCS) cases was included and considered as part of the levelised cost of electricity (LCOE) calculations.

A number of assumptions were made in the study. Hydrogen was assumed to be produced via steam methane reforming (SMR) with CCS (blue hydrogen), as almost all hydrogen produced today comes from SMR-based plants. This set the cost of hydrogen as an input into the study. Green hydrogen – produced via electrolysis using renewable power – could have been used, however it is not available at scale currently, and it comes at a higher cost. The use of green hydrogen would increase the cost of hydrogen as an input, but the net result of the study would not change.

For the purpose of this initial study, the following were reviewed out of scope: detailed plant engineering considerations, including analysis of thermal efficiency differences between fuels; inland transportation of fuels in Japan (most power plants are located on the coast, so it was assumed that this cost is reduced); regasification of liquid hydrogen, assumed to be relatively small when using seawater for heat exchange. It was also assumed that ships transporting the hydrogen and ammonia would be using conventional maritime shipping fuels.

Easier and lower-cost transportation

Based on the aforementioned assumptions, the studies concluded that, in the future, it will be cheaper to use ammonia than hydrogen as a low-carbon fuel option in power generation. Even using the assumptions that result in the highest cost of ammonia and the lowest cost of hydrogen, fuel price differential is approximately US$10/million Btu. This is primarily due to the transport cost – shipping ammonia is a quarter to a third cheaper in respect to shipping hydrogen. Shipping hydrogen requires converting it into its liquid form, which means decreasing its temperature to an ambitiously low -250°C (-418°F). It is also easier to move ammonia, because changing it from gas to liquid requires cooling it down to a temperature of only -30°C (-22°F), and there is already a well-established global shipping network for ammonia.

Ammonia transportation is already a mature technology, with 15 – 20 million t of the commodity shipped annually around the world today. However, at present there is only one ship in the world that can move liquid hydrogen. That ship, the Suiso Frontier, has a hydrogen cargo capacity of approximately 1250 m3, which is around 85 t.

Figure 2. GE and IHI Corp.’s joint study suggested that ammonia – direct or cracked to hydrogen – has a lower landed cost (and lower levelised cost of electricity) than hydrogen in Japan. Source: GE.

The studies then took the landed fuel costs and computed the associated LCOE. The LCOE for using ammonia directly was lower than that using hydrogen transported as liquid, or ammonia cracked back to hydrogen. This is not a surprise given that fuel is typically the largest component of LCOE.

The key results from this combined study, which took into consideration Japan as a case study, could be applied to other geographies that are today importing energy in the form of carbon-based fuels.

The challenge: reduce carbon emissions from ammonia production

The broader challenge is making ammonia in a way that does not emit as much carbon. Ammonia production, a process that typically uses fossil fuels, is a significant contributor to carbon dioxide (CO2) emissions, accounting for approximately 1.3% of all emissions in the energy sector, according to the International Energy Agency (IEA), who recently published a report examining the economics of using ammonia as a transport option for hydrogen.

One of the main areas of focus in the IEA report is how ammonia might be made using electrolysis or methane pyrolysis – two ways to potentially produce hydrogen with lower carbon emissions, thus lowering the carbon intensity of the final product.

Although the IEA reports that these alternative methods could cost 10 – 100% more per tonne of ammonia, the same can be said for other technologies such as producing hydrogen via electrolysis or adding CCS to steam methane reforming (SMR). The question is: which of these fuels that produce little or no carbon during combustion could yield the lowest delivered cost? Based on the assumptions used in the study, ammonia could be a lower-cost option.


The GE and IHI study concluded that relative to liquid hydrogen, ammonia is the lower-cost method and the more technologically-ready option for transporting energy over long distances. Furthermore, direct combustion of ammonia, rather than cracking to hydrogen, enables a more economical LCOE solution for gas power plants. To advance towards net zero targets, an urgent plan to reduce carbon emissions resulting from ammonia production must be developed and implemented, which in turn would open opportunities for ammonia to replace fossil fuels in other applications.

In this study, Japan is a surrogate for countries in Asia that rely on imports of carbon-based fossil fuels. These countries are considering the potential importance of lower-carbon fuel sources. And ammonia, based on this analysis, is a viable option.

Note: Passport, LM2500 and LM6000 are all trademarks of General Electric Company.

This article was written by: Dr. Jeffrey Goldmeer, GE Gas Power.

Read the article online at:

You might also like

Hystar to supply 0.75 MW electrolyser to Fortum

Hystar AS has signed an agreement with Finnish mostly state-owned energy company, Fortum, to supply a 0.75 MW electrolyser for Fortum’s hydrogen pilot plant in Källa, Loviisa, Finland.


Embed article link: (copy the HTML code below):