Global energy demand has increased drastically with the onset of the Industrial Revolution, as highlighted by Figure 3. It is worth noting that for most of human history, mankind actually lived in decarbonized societies, with energy being supplied by traditional biomass for the most part, as well as some wind and hydro (Smil, 2018). However, with the Industrial Revolution came the need for more and more concentrated energy sources, starting with coal, then adding oil and natural gas, and later nuclear power and modern renewables such as wind turbines or photovoltaic panels to the energy portfolio. At the same time, new ways to harness energy were developed, beginning with the steam engine (which is often considered the starting point of the Industrial Age), and then later the internal combustion engine, widespread electrification, various heating technologies, and today information and communication technologies.

While these technological advances undoubtedly improved quality of life globally, they have also drastically increased global energy demand which so far, is still mostly being supplied by fossil fuels. Fossil fuels such as coal, oil or natural gas offer several crucial advantages: they are abundantly available, and can be efficiently and safely transported and stored. They have high energy densities and their combustion can also provide the high temperatures needed to produce essential und ubiquitous materials such as steel, non-ferrous metals, glass, cement ceramics or chemical products.

It is worth considering that, historically speaking, there has never actually been an energy transition in the sense that one energy carrier has been almost completely substituted by another on a global level across all applications. There have, however, been cases where one energy source has lost its role in certain applications. One example is town gas, a coal or sometimes naphta-based synthesis gas. It was widely distributed and used in Europe and the United States as a fuel for cooking, heating and lighting, before it was substituted by natural gas and electricity in the latter half of the 20th century. However, even today there are regions in China where it is still in use (Gas Safety - Types of Domestic Fuel Gases and Their Properties, 2024; Kobayashi et al., 2025).

Despite all the changes in the global energy landscape, the amount of energy provided by traditional biomass is about the same as it was 200 years ago. According to the International Energy Agency, about 2 billion people worldwide do not have access to clean fuels or electricity to prepare their food and use traditional biomass such as wood or cow dung instead, with significant health hazards as a consequence. About 10% of the global population do not have access to electricity at all (International Energy Agency, 2025a).

Similarly, global coal consumption, mostly used for power generation, has yet to show a significant decline (International Energy Agency, 2025b), while natural gas consumption has been steadily increasing over the last decades (Energy Institute, 2025). The massive deployment of renewable power generation capacities in recent years, in particular wind and solar, has not yet led to a reduction of fossil fuel utilization, as global energy demand is growing even stronger.

The technological and societal progress that is a direct consequence of the Industrial Age has come at a price. The combustion of carbonaceous fuels such as coal, oil or natural gas inevitably produces carbon dioxide (CO₂) which has been identified as a greenhouse gas (GHG) that promotes global warming. Compared to pre-industrial levels, atmospheric CO₂ concentrations have more than doubled, and are today at about 425 ppm, emphasizing the scale of anthropogenic GHG emissions. Almost 75% of these anthropogenic greenhouse emissions are directly or indirectly (e.g., methane emissions from natural gas extraction, transmission and distribution) tied to energy use (Richie, 2020), with the second-biggest contributor being agriculture and forestry, another indispensable sector of human activity (cf. Figure 1, right-hand side). Consequently, global temperatures are rising, resulting in more frequent extreme weather events such as heat waves, droughts or flooding, often with severe consequences. Changing weather and climate patterns have an impact on agriculture, and have geopolitical implications as well, e.g., in terms of migration.

The obvious conclusion is that energy supply and utilization have to be decoupled from GHG emissions to limit the effects of climate change. There are additional aspects to consider, though, given the paramount importance of secure and affordable access to energy for people and economies around the world. Global energy demand is expected to increase for several reasons: quality of life is increasing globally which generally entails a higher per capita energy demand, while the world population is increasing as well. Nations have to balance their commitments to mitigate climate change with the need for a secure energy supply at affordable prices for their citizens. At the same time, new technologies, in particular Artificial Intelligence (AI), are forecast to drastically increase demand for firm power supply (Global Gas Report, 2024; International Energy Agency, 2025c), putting further stress on existing power grids already coping with increasing shares of intermittent renewable power generation.

One of the essential tools to achieve the phase-out of fossil fuels is the electrification of many end-use applications, ranging from individual mobility (e.g., battery-electric vehicles) and residential heating (e.g., heat pumps) to industrial manufacturing (e.g., electric process heating). Electricity is crucial for several reasons: it can be generated at scale from renewable sources such as wind, solar, hydro or geothermal sources, or alternatively by nuclear power, without producing GHG emissions. At the same time, electricity is a very versatile form of energy that can efficiently be transformed into either mechanical energy or heat when needed. In many end-use cases, electrification also entails substantial efficiency gains, as can be seen by comparing, for example, the efficiency of battery-electric vehicles to conventional vehicles with internal combustion engines in the transportation sector, or heat pumps (Rosenow et al., 2024) to gas-fired heating appliances in the context of low-temperature heat, e.g., for heating buildings. For other applications, e.g., high-temperature industrial process heating, efficiency gains by electrification may be less pronounced (Hasanbeigi et al., 2021; Friedmann et al., 2019).

In the context of decarbonization, the origin of electricity is essential: if the electricity is not generated by carbon-free or at least carbon-neutral means, much of the GHG emissions are just shifted from the end user to thermal power plants. In some cases, e.g., for high-temperature process heating, it can be shown that using a fossil fuel like natural gas in an industrial furnace can actually result in lower overall CO₂ emissions than a switch to an electric furnace supplied by an only partially decarbonized power grid (Leicher, 2024; Wünning, 2021), depending on the carbon intensity of the respective power grid. While the global carbon intensity of electricity has been decreasing, its evolution is dependent on the political momentum of the energy transition. For other applications, e.g., light-duty vehicles or residential heating by heat pumps on the other hand, this is less of an issue, as electrification will almost certainly lead to reduced overall emissions, as the efficiency gains are more substantial here (Rosenow et al., 2024; Naumann et al., 2022; Buber et al., 2022).

There are, however, more aspects to consider than just efficiency: many renewable energy sources, most notably wind and solar, are inherently intermittent which means they can only contribute to a firm and reliable power infrastructure in combination with suitably scaled energy storage facilities and/or flexible backup systems. This is particularly relevant for power grids as electricity supply and demand have to be continuously balanced. Other renewable options such as hydro or geothermal power are easier to integrate into power infrastructures since they can provide dispatchable power, but they are restricted by geographic and geologic suitability. Nuclear power, while being a mostly carbon-free power generation technology, faces challenges of its own: high investment costs, public acceptance, safety and security considerations as well as the question of long-term nuclear waste disposal.

Thus, the countries with the lowest CO₂ intensities in their power systems tend to rely on either hydro and geothermal (e.g., Norway) or nuclear power generation (France being the prime example), not wind or solar. Yet solar power is forecast to be the dominant source for electricity in the future (EMBER Energy, 2025; International Energy Agency, 2024b), and the integration of large shares of variable renewables into power infrastructures brings significant challenges, often leading to overall increasing system complexity and cost (International Energy Agency, 2024c).

Germany, currently the 3rd largest economy of the world by gross domestic product (GDP) and with a population of more than 80 million inhabitants, is a good example for the challenges that come with decarbonizing a modern industrialized economy. The nation has committed to become carbon-neutral by 2045 and has been investing significant funds into what is called the “Energiewende” (energy transition). In 2024, about 54% of the electricity produced in Germany came from renewable sources (mostly wind and solar, some hydro and biomass), compared to about 6.5% in 2000 (Stromerzeugung nach Energieträgern Strommix von 1990 bis, 2024). This translates however, to only about 20% of renewable energy in the final energy demand (Energieverbrauch in Deutschland im Jahre, 2024), as electricity accounted for about one-quarter of the final energy consumption. The carbon intensity of the German power mix was determined to be 386 g CO_2eq/kWh of electricity in 2023 (Energieverbrauch in Deutschland im Jahre, 2024), one of the highest values in the EU. It is insufficient to just consider electricity in the context of decarbonization, however. In fact, German industrial process heat demand alone was about en par with the entire German electricity generation from all sources in 2023 (BDEW, 2025).

One topic that has been gaining more traction in recent years is utility-scale energy storage, especially due to recent shifts in European energy supply and the growing contributions of inherently intermittent wind and solar power generation. This refers both to large-scale electricity storage, but also energy storage, e.g., in the form of natural gas. Germany today operates facilities to store about 260 TWh’s worth of natural gas, equal to almost one-third of the nation’s annual gas demand. These assets primarily serve to deal with seasonal demand shifts, as natural gas is for the most part used for residential heating and industrial manufacturing. Only about 13% of Germany’s gas demand is accounted for by power generation (Energieverbrauch in Deutschland im Jahre, 2024). In contrast, the available capacities of electric energy storage technologies are orders of magnitude smaller: in terms of pumped hydro, the current capacity is about 0.04 TWh with little potential for expansion (Schill and Kemfert, 2011). Total installed battery storage capacity is even lower with roughly 0.02 TWh in 2024 (Bundesverband Solarwirtchaft e.V., 2025), though installed battery capacities are growing rapidly. It is evident that providing security of electricity supply while relying heavily on intermittent energy sources is a challenge. Recently, Germany turned from a net electricity exporter to a net importer, although there are at the same time many instances when Germany exports surplus electricity to its European neighbors due to a lack of local storage capacity.

While the situation can be very different depending on local conditions, the example of Germany may serve as an indicator for the challenges involved in a full-scale energy transition towards renewable and sustainable energy sources for an industrialized nation.

Electricity as an energy carrier offers many advantages, but also has certain drawbacks which may limit its suitability for some end-use applications as well as its functions in energy infrastructures. Batteries have much lower energy densities compared to fuels (cf. Figure 4), which affects the available range, endurance or payload capacity of vehicles like aircraft or ships, despite the higher efficiencies of the drive systems themselves. In the context of electricity infrastructures, utility-scale batteries can serve to provide electricity in the range of several hours which is sufficient for short-term generation shortages or peak-shaving, but they are unable to compensate for insufficient power generation over days or weeks (the so-called “Dunkelflaute”). This is highlighted by Figure 5, where various energy storage technologies are compared in terms of discharge durations and storage capacities. Only the so-called power-to-X technologies and pumped-storage solutions offer decarbonized long-term energy storage at utility scale. It has been the traditional role of fossil fuels to provide long-term energy security, which is particularly relevant for energy-intensive industries. In Germany, for example, the natural gas grid transports about twice as much energy as the power grid (BDEW, 2025).

While the main role of fossil fuels today is to provide primary energy for the global energy system, coal, oil and natural gas serve other vital functions in terms of security of supply, grid balancing, energy storage and global distribution of energy. Fossil fuels are also an important feedstock for plastics, fertilizers and other chemicals, and serve as reducing agents in metallurgy. According to (Lieuwen et al., 2024), about 10% of the consumption of fossil fuels in the United States is accounted for by this non-energetic use, the share is likely similar in other parts of the world.

The functions fulfilled by fossil fuels in today’s global energy system will still be required in a decarbonized future, and electricity alone seems incapable of fulfilling all these roles. Currently, both short and long-term deficits of renewable power generation are usually compensated by conventional thermal power plants, although in some countries, e.g., France, the output of nuclear power plants is modulated as well when required (Cany et al., 2018). At least for short-term grid load balancing, batteries are expected to play a much bigger role in the future. This trend can already be observed in the Californian power grid, though in 2024, the state still imported about 22% of its electricity demand from neighboring states (California Energy Commission, 2025). For longer periods of insufficient renewable power generation, dispatchable power generation capacities will still be required (International Energy Agency, 2024c).

Similarly, about 40% of global maritime shipping (UN Trade & Development Data Hub, 2025) serve to distribute energy around the world by transporting coal, oil and liquefied natural gas (LNG) today. Power grids, on the other hand, are typically used to distribute electricity over comparatively short distances over land. Given that the potentials for renewable energies, but also energy demands vary significantly around the world, the global distribution of decarbonized energy is a challenge that needs to be addressed, Global supply routes of hydrogen or hydrogen carriers from renewable sources are being discussed (Global Hydrogen Flows, 2022), as well hydrogen grids (Martin et al., 2024; Khayatzadeh et al., 2025; van Rossum et al., 2022) and HVDC power lines (HVDC: high voltage direct current) (H and umpert, 2012).

Synthetic fuels are one option to address these challenges: electricity from renewable sources is used to produce hydrogen (or hydrogen derivates) and potentially synthetic hydrocarbons which then serve to store and transport energy at the scales required. Other options include bio-fuels (Ireson, 2022; Fiehl et al., 2017; Raina et al., 2024) or even metal fuels (de Goey, 2022; de Goey, 2025). All options have their specific advantages and drawbacks. Biomass potential, for example, is limited and there are ethical considerations as well, such as the “food-vs.-fuel“ discussion (at least in case of 1^st generation biomass). Biomass may be better utilized as a sustainable carbon source for the chemical industry instead of being used as fuel. The application of metal fuels on the other hand will likely be technologically restricted to certain use cases.

Especially when considering synthetic fuels such as hydrogen, ammonia or synthetic hydrocarbons, the benefits of using a fuel need to be weighed against the efficiency losses that inevitably come from fuel production and distribution, but also from combustion itself, as the direct use of electricity will almost certainly be more efficient. Similarly, the efficacy of synthetic fuels to reduce GHG emissions has to be considered over their entire life cycle and compared with alternative options, e.g., by conducting thorough life cycle assessments of direct electrification and the use of so-called “blue” and ”green” hydrogen (i.e., hydrogen from steam reforming of natural gas with subsequent carbon capture and storage and hydrogen from electrolysis using renewable electricity) (Kaiser and Chowdhury, 2025; Uchida et al., 2025). In the case of synthetic hydrocarbon fuels, the origin of the required carbon has to be taken into account as well. There are applications, however, where the use of synthetically or biologically produced fuels seems inevitable, for instance in long-haul aviation and shipping (Lieuwen et al., 2024; Dreizler et al., 2021). Due to the low energy densities and high weight of even the most modern and advanced batteries, electric propulsion systems simply are not a technologically viable option here to achieve the necessary ranges, endurances and payload capacities. Instead, the respective industries are actively looking into synthetic aviation fuels (SAF) (Van Dyk and Saddler, 2021; Wang et al., 2024) or alternative fuels such as ammonia (Hansson et al., 2020) and methanol (From pilots to practice, 2025) in the context of maritime propulsion. Often, compatibility of new fuels with legacy equipment and infrastructure is a concern as well (Khayatzadeh et al., 2025; Uchida et al., 2025).

In other sectors, both increasing electrification and the use of alternative fuels are likely to play key roles in their decarbonization efforts, e.g., in high-temperature industrial process heating. It is generally expected that most of low-temperature process heating will be electrified, though biogenic fuels will also be used to some degree. The situation is, however, less clear-cut in high-temperature heating which is particularly relevant for many primary materials industries, e.g., metals, cement, glass or ceramics industries. The important role of synthetic fuels, and hydrogen in particular for high-temperature process heating, is highlighted in Figure 6, taken from (Fleiter et al., 2023), an extensive study where the shares of various energy sources for process heating both for low and high temperature applications (T > 300 °C) were estimated for different policy scenarios within the European Union and the United Kingdom. In total, three different scenarios were explored in this study: “Elec+” describes a policy scenario where the focus is on electrification as the primary pathway towards decarbonization. Correspondingly, “H2+” employs the use of hydrogen (from renewable sources) as the main tool. “Elec+_VC” finally is similar to “Elec+” but assumes that many energy-intensive intermediate products such as sponge iron or base chemicals will be imported into the EU27+United Kingdom by 2050. According to the study, the majority of low-temperature process heat will be provided by electricity, except for the “H2+” scenario where hydrogen plays the biggest role. More interesting, however, is the case of high-temperature process: across all considered scenarios, the shares of both electricity and hydrogen are roughly equal. This underlines that especially in high-temperature process heating, there will be many applications where synthetic fuels, despite their inherent challenges, will be the best option overall.

These findings highlight the complexity and diversity of high-temperature process heating. There are several reasons why hydrogen in particular is expected to play a significant role in energy-intensive industrial manufacturing processes: while electric heating tends to be more efficient, there can be technological limitations in terms of achievable heat flux densities, resulting either in reduced production rates or bigger furnaces (Fleiter et al., 2023; Leicher et al., 2024). Other considerations may concern product quality: many manufacturing processes involve more than just heat transfer. For some products and materials, the interaction between the material and the furnace atmosphere, e.g., in terms of O₂ concentrations in the flue gas, can be just as relevant to achieve the desired product qualities. In other cases, for example, aluminum recycling, electric furnaces cannot accept scrap which is strongly contaminated with organic residues from paints, lubricants or varnish, or, in the case of glass melting, large quantities of cullet, i.e., recycled glass. Also, dark glass colors are difficult to produce electrically today (Meuleman, 2024). Many energy-intensive industries therefore pursue both increasing electrification and alternative fuels as decarbonization options, often depending on the specific product and process (Zier et al., 2021; Zier et al., 2023; Dell and a Rocca, 2025).

Finally, there is the question of balancing the power grid and ensuring security of electricity supply while integrating large shares of intermittent energy sources like wind and solar into power grids. Batteries and demand side management are valuable tools, but limited in scope to relatively short time spans and small capacities, compared to dispatchable fuel-based power generation options. Correspondingly, all major gas turbine manufacturers develop gas turbines which can be operated with hydrogen (in some cases also ammonia). Security of supply, grid balancing and cost optimization are prioritized by policymakers (Einigung zur Kraftwerksstrategie, 2024; Fuel Cell Works, 2025), despite the inherent loss of overall efficiency, compared to a fully electrified energy system. In fact, despite higher overall efficiencies and low power generation cost, an all-electric energy system is not likely to be more cost-effective than the existing fossil-fuel-based system, as the advantages of renewable electricity are counteracted by higher expenses for energy storage and transmission (Ueckerdt et al., 2013; Idel, 2022; Matsuo, 2022; Helm, 2025).

These considerations are reflected in forecasts about the share of electricity in final energy use. Lieuwen et al. (Lieuwen et al., 2024) for example, predict that in a net-zero cost-optimized U.S. energy system in 2050, about 52% of the final energy consumption will be accounted for by electricity, compared to 22% today, as is shown in Figure 7. The share of fossil fuels in primary energy is predicted to drop from 83% to 19%, while the share of “renewable fuels” in the end energy mix, in this context comprising both biogenic and synthetic fuels, is expected to increase by a factor of four. Evidently, the Americans also consider the continued use of some fossil fuels to be inevitable and plan to deploy carbon capture and storage technologies (CCS) or other carbon removal options to account for that. Wissmiller et al. (Nasta and Wissmiller, 2024) come to similar conclusions.

In a similar vein, a report of EURELECTRIC (the Federation of the European Electricity Industry (Final report, 2023)) expects a share of electricity between 58 % and 71% in the end energy mix for the EU and United Kingdom by 2050, depending on various European policy frameworks (cf. Figure 8), the rest being synthetic and biogenic fuels of some kind.

These studies underscore, however, that the role of fuels (and hence combustion) will change drastically in a decarbonized energy system of the future. Fossil fuels will no longer provide most of the primary energy needed, but instead, synthetic and biogenic fuels will serve to complement electricity from renewable and other sustainable sources to reliably provide energy when and where it is needed, and in whichever form it is required. This, of course, has consequences for the way combustion processes are designed and applied. Also, the advantages of using these fuels instead of direct electrification has to be weighed against the inherent inefficiencies which come with producing and using synthetic fuels.

Flexibility is going to be a key feature for combustion applications in a decarbonized energy system, and it may come in many forms. Load flexibility is one aspect, both on the power generation side where both batteries and thermal power plants will be required to compensate for the volatility of wind and solar at different scales in terms of time and capacity, and to ensure security of supply. Power grids need to be balanced constantly in electricity demand and supply which means that for thermal power plants in particular, dynamic operation may well become even more relevant than efficiency. This trend can already be seen in the thermal power plant market in Europe: while historically, thermal power plants, especially those designed for baseload operation such as coal-fired plants, were designed for maximum efficiency in a relatively narrow operational window, the focus today is on units that can be ramped up and down quickly, as the grid requires. Gas turbine power plants in particular are considered well-suited for this task. But the need for greater flexibility is also found on the end-use side, for example, in the form of demand-side management, i.e., industrial production processes which can change their load profiles to help stabilize grid infrastructures (Estelmann et al., 2018; Ausfelder et al., 2019; Fleischmann, 2018). Another option could be hybrid industrial furnaces and kilns that can switch between different energy carriers such as electricity and hydrogen, which could serve to help balance the power grids by providing ancillary and grid-services. In each of these applications, firing rates need to be modulated quickly, while at the same time complying with other requirements for equipment operation, e.g., maintaining combustion stability, pollutant emissions limits and, where applicable, product quality, is still needed. This, in combination with the need to use new, carbon-free or at least carbon-neutral fuels, provides new topics for applied combustion research. Hybrid furnaces and kilns are an interesting decarbonization option from another perspective as well. Hybrid heating itself is not new (Meuleman, 2024; Glass Online, 2021), but has so far usually been used to improve either the production process or for reasons of product quality, as operation with fossil fuels is often more economic today. For example, most modern gas-fired glass melting furnaces are equipped with booster electrodes (Zier et al., 2021) which serve both to provide additional energy input into the melt when needed to temporarily increase production, but also to control flow patterns in the molten glass to improve glass quality. In today’s glass melting furnaces, around 10% of the overall energy input is provided by these electrodes (Overath, 2023). Future designs are planned to increase the electric energy input significantly as part of the industry’s decarbonization efforts in their larger furnaces (e.g., for flat glass production), in addition to fully electric furnaces for smaller production rates (Meuleman, 2024; Zier et al., 2021). Current plans indicate that the oxy-fuel combustion of hydrogen will serve to fill the gap between the energy that can be electrically introduced into the furnace and the overall energy demand to achieve the desired production rates and qualities (Leisin and Radgen, 2022). Full electrification is often not an option, at least for larger glass melting furnaces, as the heat flux densities that can be achieved by electrodes are limited which severely limits production rates. There are also limitations in terms of some glass qualities and the integration of large shares of recycled glass in fully electric melting processes (Meuleman, 2024). Modern electric arc furnaces, used for steel scrap recycling, are also usually equipped with supersonic gas-oxygen burners which serve multiple purposes: they provide additional energy input and can compensate for hot spots produced by the electrodes, reduce electrode degradation and improve overall efficiency, especially in the early phase of the production cycle when the scrap is still mostly solid in a packed bed and electric heating is therefore relatively inefficient. In the later stages of the cycle, once the metal is molten, the heat input is provided electrically while the burners serve as oxygen lances to inject oxygen into the melt. Equipment manufacturers are adapting these burners to operate with hydrogen or natural gas/hydrogen blends (Schüttensack et al., 2024; Krause et al., 2022).

Possibly the biggest challenge from a combustion point of view is the investigation of new fuels and their utilization in different kinds of equipment and applications. Some of the alternative fuels which are being discussed in the context of decarbonization have quite different combustion characteristics compared to conventional hydrocarbon fuels such as natural gas. Table 1 gives an overview of some essential fuel properties and combustion characteristics of methane (CH₄, representing here natural gas as a reference, but also biomethane and synthetic natural gas (SNG)), hydrogen (H₂), ammonia (NH₃), dimethyl ether (DME, CH₃OCH₃), a possible replacement fuel for liquefied petroleum gas (LPG), and methanol (CH₃OH). Both ammonia and methanol are discussed as fuels to decarbonize high-sea shipping (The Lloyd’s Register Maritime Decarbonisation Hub, 2022). It is evident that the hydrocarbon fuels show quite similar properties and combustion characteristics when considering the gaseous phase of methanol (the condensation temperature of CH₃OH is 65 °C under standard conditions). This indicates that the changes necessary to adapt existing combustion applications to these “new” hydrocarbons should be relatively minor. The challenge in utilizing synthetic hydrocarbons lies not so much in the actual combustion, but in sourcing sufficient carbon from biogenic or other carbon-neutral sources, and in the overall efficiency of the production process, as each additional conversion process incurs additional efficiency losses. Hydrogen and ammonia, on the other hand, allow for a completely CO₂-free combustion, as long as these fuels are produced in a climate-neutral way, though it is worth pointing out that today, the vast majority of hydrogen is produced from hydrocarbons with significant GHG emissions at the site of its use (International Energy Agency, 2025d), primarily as a feedstock in the (petro-)chemical industry. Hydrogen has been a key component of decarbonization strategies for some time, especially for hard-to-electrify applications, while ammonia has so far mostly been considered as a hydrogen carrier medium, e.g., for the intercontinental transport of energy, as it is easier to store than compressed or liquid hydrogen. In recent years, however, there has also been a growing interest in the direct thermal use of ammonia (Kobayashi et al., 2019; Val et al., 2024; Valera-Medina, 2023), despite it being a toxic substance and a challenging fuel. In addition to its potential as a maritime fuel, ammonia could be interesting for stationary applications as well to supply fuel-based, decarbonized energy to remote locations that are not adequately connected to decarbonized energy infrastructures (Valera-Medina, 2024). Hydrogen and ammonia, are quite different fuels compared to hydrocarbons in terms of caloric properties like calorific values and the corresponding minimum oxygen and air requirements. These differences can be accounted for by changing the required volume flows of fuel and oxidizer in a technical combustion process. Even when considering caloric properties alone, some consideration is still required, however: for example, the Wobbe Index (cf. Table 1), often considered the most relevant interchangeability criterion for gaseous fuels (Slim et al., 2011; Guidebook to Gas Interchangeability and Gas Quality, 2011), can only reasonably be applied to evaluate the interchangeability of chemically similar fuels (Leicher et al., 2022a). The comparison of methane and hydrogen is a good example here: though the Wobbe Indices only differ by −9.4%, combustion characteristics such as laminar combustion velocities or adiabatic combustion temperatures change drastically when switching from methane to hydrogen. CH₄/N₂ or CH₄/CO₂ blends with similar Wobbe Indices as pure hydrogen will, however, still behave more like pure methane than hydrogen in terms of combustion (Leicher, 2025). Arguably more important and technologically more challenging from the perspective of combustion, crucial characteristics such as adiabatic combustion temperatures, laminar combustion velocities and minimum ignition energy can be extremely different. In many ways, hydrogen and ammonia in particular are very different fuels, especially when compared to methane: the laminar combustion velocity of hydrogen is significantly higher than that of methane, while ammonia exhibits much lower laminar combustion velocities. The minimum ignition energy (MIE) of H₂ is much lower than that of typical hydrocarbons, whereas the MIE of NH₃ is orders of magnitude higher. This highlights the challenge to achieve a stable combustion process with pure ammonia (Biebl et al., 2025). There are safety aspects to consider as well: hydrogen is much easier to ignite than methane, while ammonia is toxic.

The differences in the laminar (and consequently, turbulent) combustion velocities in particular can pose significant challenges for the design of combustion equipment, especially for premixed burners which are today very common in modern gas turbines (Shivam et al., 2025; Gruber, 2025). For heavy-duty gas turbines in the power sector in particular, flame stabilization and safety-relevant issues such as flame flash back, flame lift-off and flame supervision are of special concern. Given the large differences between these new fuels and common fuels such as natural gas, the potential to retrofit existing equipment is limited. New combustion technologies are required which take the peculiarities of hydrogen into account combustion (Lieuwen et al., 2024; Berger et al., 2022; Pitsch, 2022; Noble et al., 2021). Many gas turbine manufacturers favor either some kind of staged or sequential combustion process, or multiple smaller non-premixed hydrogen flames instead of one lean premixed flame, (Noble et al., 2021) (Tekin et al., 2018; Shivam et al., 2025; Bothien et al., 2019). Non-premixed burners, on the other hand, have already been shown to be more resilient, especially in the context of hydrogen as long as firing rate and air excess ratio are kept constant. This form of combustion can be predominantly found in thermal processing industries. Many non-premixed burners originally designed for natural gas have been proven to run safely with natural gas/hydrogen blends or even pure hydrogen, although other challenges, e.g., nitrogen oxides (NO_X) emissions, remain (Islami et al., 2024; Meynet et al., 2023; Gitzinger et al., 2022; Huber, 2021). Some investigations, based on both CFD simulations (CFD: computational fluid dynamics) and experiments in semi-industrial test rigs highlight that the heat transfer performance is hardly affected by a fuel switch even to pure hydrogen in quantitative terms, though the radiation characteristics of hydrogen flames are very different from natural gas flames. This is highlighted, for example, by Figure 9, which showcases temperature and heat flux distributions from CFD simulations of a 30 MW float glass furnace operated with either natural gas as a reference case or hydrogen (Islami et al., 2024). As long as the fuel properties are adequately accounted for in the furnace control system and firing rate and air excess ratio are kept constant, the heat fluxes into the glass melt are almost identical. These findings are corroborated both by further CFD studies for oxy-fuel glass melting furnaces (Daurer et al., 2024), but also by measurements in a semi-industrial test rig (Meynet et al., 2023) for natural gas/hydrogen blends, as visualized in Figure 10. Similarly to the simulations, these experiments with firing rates between 100 and 300 kW and hydrogen admixture rates up to 50 vol.-% show that cooling requirements (which would correspond to the usable heat in the context of process heating), is hardly affected by the change in fuel composition, as long as the main combustion-related parameters, i.e., firing rate and air excess ratio, are maintained constant. Consequently, retrofitting existing combustion equipment used for industrial process heating can be expected to be far easier, especially in the context of hydrogen, than a conversion to electric heating. These examples highlight that when discussing the use of alternative fuels for any given purpose, it is essential to consider both the fuel and the actual combustion technologies implemented. A heavy-duty gas turbine for power generation is, technologically speaking, very different from an industrial furnace in the metals, glass or ceramics industries.

Despite the need to decarbonize, operators of industrial equipment will still have to comply with increasingly stricter environmental regulations in terms of pollutant emissions. Nitrogen oxides (NO_X often play a central role here and NO_X emissions reduction has been a long-standing focus of combustion research over the last decades. NO_X emission performance has to be considered when discussing alternative fuels such as hydrogen or ammonia. With most gaseous fuels, NO_X formation is primarily controlled by the thermal NO_X formation pathway: it is dependent on local temperatures and the simultaneous availability of oxygen in the process. Thus, hydrogen, given its much higher adiabatic combustion temperature when burned with air, has the potential to produce significantly higher emissions of NO_X than natural gas. However, most primary measures to inhibit NO_X formation, for example, flameless oxidation/MILD combustion (Cellek, 2020; Mayrhofer et al., 2021), fuel and/or air staging (Bothien et al., 2019), flue gas recirculation (Huber, 2021), or oxy-fuel combustion (Leicher and Giese, 2025) (von Schéele et al., 2022), work with hydrogen just as well as with conventional gaseous fuels as the NO_X formation mechanism remains the same. It has been shown that in many applications of non-premixed combustion, equal or even lower NO_X emissions can be achieved when burning hydrogen, compared to natural gas (Leicher and Giese, 2025; Astenasio et al., 2023a).

NO_X emissions from ammonia combustion, however, follow very different formation routes as they are dependent both on the thermal pathway, but also on the oxidation of fuel-bound nitrogen to nitrogen oxides (Kobayashi, 2025). NO_X emissions from ammonia combustion can potentially be extremely high compared to the combustion of natural gas or hydrogen and require somewhat different mitigation approaches. In fact, in addition to actually achieving a stable ammonia combustion, reducing its NO_X emissions is one of the major technological challenges for the use of this carbon-free fuel (Kobayashi et al., 2019; Val et al., 2024). (Islami et al., 2024).

While thermal NO_X is, for the most part formed in the post-flame region and thus also increases with the residence times in the hot reaction and post-reaction zone, NO_X formation during the combustion of ammonia behaves fundamentally differently, as is visualized in Figure 11. NO_X peaks occur in the flame itself as part of the NH₃ oxidation process and then relax towards equilibrium values with increasing residence time. The availability of oxygen is one constraint for NO_X formation, which is why near-stoichiometric combustion can help reduce NO_X emissions. In addition to well-established pollutant species such as NO_X, other pollutants have to be considered as well, namely, nitrous oxides (N₂O) and NH₃ itself. Similarly to hydrogen combustion, the ways to achieve stable low-NO_X NH₃ combustion can differ greatly, depending on the actual application. Some gas turbine manufacturers are looking into staged combustion processes (often called RQL combustion in the context of gas turbines, Rich-Burn, Quick Quench, Lean-Burn (Kobayashi et al., 2019)) while in the context of non-premixed combustion, air staging (Biebl et al., 2025) or exhaust gas recirculation (Biebl, 2025) have been shown to help mitigate NO_X formation.

The need to decarbonize hard-to-electrify applications makes new fuels interesting options which previously would not have been considered worthwhile. At the same time, the wide variety and high degree of specialization found in large-scale stationary combustion processes mean that the task of successfully converting these processes and applications to new fuels such as hydrogen or ammonia are not restricted to combustion alone, but also to questions of product quality, effects on refractory materials and operational safety. There is also the issue of economic viability, in competition to direct electrification, but also in comparison to conventional and established fossil fuels, even when taking account aspects such as carbon taxes. Both in the case of electrification and the adoption of new fuels (particularly hydrogen, in this context), the impact on energy supply infrastructures needs to be considered as well. This is especially relevant for energy-intensive industries which usually require a continuous energy supply.

For hydrogen in particular, many of the combustion-related challenges have already been successfully addressed on the lab and semi-industrial scale, at least in the context of industrial process heating. Heat transfer performance and hence furnace efficiency have been shown to be quite similar to conventional natural gas combustion (Islami et al., 2024; Meynet et al., 2023). Many burner manufacturers have introduced hydrogen-ready products into the market or are actively investigating how their existing portfolio of products performs with both pure hydrogen and natural gas-hydrogen blends (Gitzinger et al., 2022; Huber, 2021; Astenasio et al., 2023b; Astenasio et al., 2023a; Mohanna et al., 2025).

Some often highly application-specific questions remain, e.g., the impact of hydrogen combustion on product or refractory quality (HyInHeat - D2, 2024). Investigations for the glass industry (Leicher et al., 2022b; Walter et al., 2024; Caudal and Riauté, 2025) show that while there can be changes in color and other glass quality criteria due to hydrogen combustion (compared to natural gas, the dominant fuel in the glass industry today), these changes often are not directly related to the hydrogen itself, but caused by the higher water vapor concentration in the furnace atmosphere when burning hydrogen. They can be compensated by modifications of the melting process parameters and ingredients in the raw materials. Investigations for the tiles and bricks industry come to similar conclusions (Poirier et al., 2025).

For the steel and aluminum industries, effects of hydrogen combustion on aluminum quality seem to be highly dependent on the actual product being investigated, with some more sensitive than others (Koslowski et al., 2025; von Schéele and Zilka, 2020; Cirilli et al., 2025; Haapakangas et al., 2024; Airaksinen et al., 2023; Schwarz et al., 2025). Similarly, some commonly used refractory materials have been shown to be resistant to hydrogen or water-rich furnaces atmospheres, while others are more sensitive (Poirier et al., 2024a; Poirier et al., 2024b; Konschak et al., 2025). None of these issues seem to be insurmountable, and (von Schéele and Zilka, 2020) reports on a number of furnace installations in the steel and aluminum industries in Scandinavia already being routinely operated with hydrogen produced from hydropower.

The challenge of adopting hydrogen (and potentially ammonia) for decarbonizing industrial process heat and power generation is two-fold: there is a lack of experience with hydrogen combustion in full-scale processes which, given the size, cost and complexity of these pieces of equipment, is essential to generate trust in inherently risk-averse industries (Ancheyta, 2024), and there is the question of an adequate supply of fuel at economically viable prices.

While the first hydrogen-ready combustion equipment has become commercially available and some first “H2-ready” furnaces and gas turbines have already been commissioned, the task of even temporarily exploring the use of hydrogen as a fuel in an industrial manufacturing environment involves not only scientific and engineering expertise, but is also a significant logistical effort, considering the quantities of hydrogen required, even with only a partial conversion of an existing plant. Keeley (Keeley, 2022) describes an industrial-scale investigation in a publicly funded research project in the United Kingdom where a 50 MW float glass furnace was to be operated with various hydrogen admixture rates (up to 20 vol.-%) into natural gas. Also, a single burner port was planned to be fired with 100% hydrogen. However, it was impossible to obtain neither the necessary quantities of hydrogen nor the trailers to transport the H₂ to the glass production site so that in the end, the admixture rate had to be limited to just 15 vol.-% for the full-furnace investigations. Single-port investigations were carried out with 100% H₂. Even so, trailers had to be switched about every 40 min to maintain a constant hydrogen supply to the furnace. Even just positioning multiple trailers on the premises while complying with safety regulations required extensive preparations. This example highlights the scope and complexities of full-scale industrial testing, which, however, is an essential step for the implementation of hydrogen (or other alternative fuels) both in the industrial manufacturing and power generation sectors. Publicly funded research projects can help mitigate these risks to a degree, and in fact, several such projects are being carried out to address these challenges in different parts of the world (Valera-Medina, 2024; HyInHeat - D2, 2024; Leicher et al., 2020; H2AL, 2024; Caccamo, 2025).

Though many technical questions are specific to a given purpose, some common considerations remain relevant for almost all applications. The biggest uncertainties for industrial-scale implementation of hydrogen (or other alternative fuels) today remain cost and logistics: the cost of hydrogen from carbon-free or neutral sources at scale is yet unknown (but expected to be highly dependent on local conditions (International Energy Agency, 2019)), and given the quantities required in energy-intensive industries or power generation, a hydrogen infrastructure will be required to ensure security of supply and cost-efficient transport at scale. The construction of such infrastructures is just getting started, e.g., the “Hydrogen Backbone” in north-western Europe (van Rossum et al., 2022). This creates a chicken-and-egg situation where industries are hesitant to commit due to lack of firm hydrogen supply while the extension of the growing hydrogen infrastructure is shaped by confirmed hydrogen demand from industry and the power sector. Some authors also question to what degree existing natural gas infrastructures can be repurposed for hydrogen (Martin et al., 2024), while the global gas industry seems confident that this is manageable (see, e.g., (Khayatzadeh et al., 2025)). The situation is similar for other alternative fuels where costs and availability are yet unclear.

Japanese companies have already demonstrated the technological viability of intercontinental shipping of liquefied hydrogen with a relatively small demonstration vessel and the corresponding loading and off-loading facilities in Australia and Japan respectively (Ohashi, 2022), but are currently holding off on producing bigger vessels. Similarly, the business case for a hydrogen-fired power plant which is to complement a power grid primarily supplied by intermittent wind and solar power generation is equally unclear as of yet, given that its annual runtime is expected to be low.

The lack of infrastructure is, however, a problem that is not restricted to hydrogen alone. In many countries, today’s power grids were never designed to continuously provide large quantities of electricity (let alone low-carbon electricity) to industrial users. This has traditionally been the role of natural gas grids. This strain on existing power grids is further acerbated by the forecasts for a growing demand for firm electricity supply for data centers and Artificial Intelligence, which is expected to increase rapidly in the coming years (International Energy Agency, 2025c). While some of these issues can be compensated to a degree by increased interconnectivity between national power grids (as is already the case in Europe, for example,), this measure alone will not be sufficient, considering the drastically increasing electricity demand that comes with widespread electrification.

Many of the economic challenges described here are rather similar in the context of alternative fuels for transportation applications, namely, in long-haul aviation or maritime shipping. Growth rates for synthetic climate-friendly fuels such as SAF or methanol (for shipping) are lower than expected (Disappointingly Slow Growth, 2024; S & P Global, 2024) and the new fuels are not yet economically competitive with conventional fuels.

Again, cost and supply are the main challenges, not technology itself.

The large-scale deployment of wind and solar power generation or electric vehicles was supported by a variety of policies ranging such as fixed feed-in tariffs, tax reductions or public subsidies. Similarly, the growth of alternative fuels for stationary, but also mobile applications, will depend on initial support from policymakers, especially when competing with fossil fuels (Brand et al., 2025). Such measures may range from tax breaks (and/or carbon taxes), emissions trading systems (ETS), contracts for difference (CfD), mandated quotas for renewable fuels or even outright state planning, such as the 15th Five-Year Plan in the People’s Republic of China (2026–2030) (Jargad, 2025; Xin, 2025) which, for example, specifically emphasizes the role of hydrogen as a secondary energy source for transportation, industry and power generation. The actual support mechanisms vary significantly, depending on national policies and circumstances.

When considering the economic viability of alternative fuels, be it for stationary or for mobility applications, it is generally insufficient to just consider the Levelized Cost of Energy (LCOE): due to the high degree of volatility of wind and solar power, additional measures such as batteries or expanded grid infrastructure are required to ensure security of supply. However, these aspects are not taken into account by the traditional definition of the LCOE which looks at power generation alone. Therefore, other metrics, e.g., full-system LCOE have to be used to assess the overall economic performance of alternative fuels (Ueckerdt et al., 2013; Idel, 2022; Matsuo, 2022; Moraski et al., 2025). Additional factors have to be taken into account as well, e.g., the potential repurposing of existing infrastructures (e.g., natural gas pipelines (Khayatzadeh et al., 2025) or refueling stations) for use with synthetic fuels, reducing investment costs.

Finally, there are also regulatory issues to consider, e.g., concerning hydrogen qualities in future hydrogen grids. In the EU, there is a consensus developing that there should be two groups of hydrogen quality, one mostly intended for thermal use (a minimum H₂ concentration of 98 vol.-% is proposed here) and one group of higher purity for more sensitive end-use applications such as fuel cells or processes in the chemical industry (Technische Regel - Arbeitsblatt DVGW G260 A and Gasbeschaffenheit, 2021; Hydrogen Quality Specification, 2022). In some cases, e.g., hydrogen-powered vehicles and their refueling stations, international standards are already in place (e.g., ISO 19880). In same instances, e.g., with SAF, these fuels can often be specifically designed to comply with existing fuel standards, allowing for the continued use of equipment and infrastructure.

Another question is how to quantify and compare the emissions of air-quality relevant pollutants like NO_X fairly and consistently between different fuels and even electricity. The current industrial practice in the EU and elsewhere is to prescribe NO_X emission limits as concentrations in the dry flue gas that equipment operators have to comply with. However, if fuels change significantly, e.g., when switching from natural gas to hydrogen, this is no longer a valid approach as the flue gas composition, particularly the water vapor content, change drastically. NOx concentrations in the flue gas of a natural gas combustion thus cannot easily be compared with emissions from a hydrogen combustion process, so either conversion factors or alternative metrics to quantify pollutant emissions are needed (Leicher and Giese, 2025; Leicher and Giese, 2024; Schmitz et al., 2023; Douglas et al., 2022), e.g., in the form of [mg_NOx/t_product] or [mg_NOx/MJ], i.e., referenced to a product quantity or the energy input into the process. These new metrics would even allow a meaningful comparison of emissions from fuel-based heating with emissions from electric heating equipment in a consistent manner. For example, the German emissions regulations (Umweltmessung, 2021) already prescribe NO_X emission limits for fully electric glass melting furnaces, using the unit [mg/t_glass]. Figure 12 shows a comparison of NO_X emissions in different metrics, based on experiments on a semi-industrial scale (Leicher and Giese, 2025).