The evolution of maritime fuels over the next decades will depend on a combination of regulation, production costs, availability of raw materials, investment decisions by shipowners, and port capacity to supply the new energy alternatives. A study jointly conducted by the Global Centre for Maritime Decarbonisation (GCMD) and Boston Consulting Group (BCG) analyzes these variables through different scenarios up to 2050, highlighting that the level of penalties on emissions is among the main factors that can alter the competitiveness of conventional fuels and the new options.
The report, titled Navigating the Maritime Fuel Transition, is based on an integrated model that relates climate policies and fuel costs to decisions about engines, fleet evolution, energy consumption, and, ultimately, supply needs in ports. The authors' goal is not to establish a single trajectory for the transition but to study under what economic and regulatory conditions different alternatives can become competitive.
The analysis includes conventional fuels such as very low sulfur fuel oil (VLSFO) and fossil LNG, as well as an option based on VLSFO with onboard carbon capture systems. Among the new fuels considered are first and second generation biodiesel, hydrotreated vegetable oil (HVO), bio-LNG, biomethanol, first and second generation bioethanol, blue ammonia, e-methanol, and e-ammonia. The model compares all of them on a common energy basis and considers six engine configurations, including dual solutions for LNG, methanol, ammonia, and ethanol.
One of the elements that conditions the 2050 outlook is the pace of renewal of the global fleet. GCMD and BCG estimate a lifespan for ships of between 25 and 30 years and calculate that only around 4% of the fleet is renewed each year. Thus, the engines ordered in the coming years will determine a substantial part of the fuels that ships will be able to use in the following decades.
The report develops three regulatory scenarios. The first takes as a reference the Net-Zero Framework (NZF) from the International Maritime Organization, with a maintained Tier-2 penalty of $380 per ton of CO2 equivalent until 2050. A second scenario gradually raises this penalty from $380 between 2028 and 2030 to reach $700 per ton in 2050. The third analyzes the application of the EU ETS and FuelEU Maritime without the existence of an equivalent global framework.
The regulatory starting point remains subject to change. The document recalls that the NZF, initially agreed upon during MEPC 83 of the IMO, held in April 2025, has seen its formal adoption postponed to the extraordinary session in October of that year. Since then, alternative proposals have been made that must be considered before MEPC 85, scheduled for December 2026. Therefore, the baseline scenario used by the study constitutes a modeling hypothesis and not a prediction of what the final approved mechanism will be.
With the penalty of $380 used in the baseline scenario, GCMD and BCG calculate that the new energy options do not achieve widespread competitiveness against conventional fuels during the analyzed period. Temporary incentives for zero or near-zero emission fuels initially reduce the cost difference, but the model foresees that, as these supports disappear during the 2040s, conventional fuels once again become economically more favorable in many cases.
This situation has a direct effect on the difference between the installed engines and the fuels actually consumed. In the baseline scenario, conventional engines would represent 24% of the fleet in 2050, conventional engines with carbon capture systems 30%, and dual-fuel LNG engines 22%. Dual-fuel methanol engines would reach 10% and ethanol engines 9%. However, having an engine compatible with a new fuel does not necessarily imply its usage if the conventional fuel remains more economical.
The report uses methanol to illustrate this difference. In the baseline scenario, dual-fuel engines prepared for methanol would represent around 10% of the installed capacity, but the fuel would only contribute about 2% of the energy consumed by the fleet. In the case of ammonia, the engine capacity would reach approximately 4%, against an energy consumption close to 2%. This difference is due to the ability of dual-fuel engines to continue operating with VLSFO or other fuels when their cost is lower.
The result changes when the model increases the penalty associated with the IMO mechanism to $700 per ton of CO2 equivalent. Under this assumption, new fuels start to compete economically with fossil fuels in a greater number of cases. Compared to the baseline scenario, the share of conventional engines, those equipped with carbon capture, and dual LNG engines decreases, while the configurations prepared for methanol, ethanol, and ammonia increase.
In this scenario, new fuels, including those drop-in that can be used in conventional engines, would represent approximately 61% of the energy consumption of the global fleet in 2050. The VLSFO used with onboard carbon capture would provide another 26%, while conventional VLSFO and fossil LNG would jointly account for around 13%.
The exclusively regional application of European standards produces a different outcome in the model. The report estimates that the routes affected by EU ETS and FuelEU Maritime represent approximately 20% of the energy consumption of international maritime transport. Within that scope, the requirements regarding greenhouse gas intensity shift consumption towards alternatives with lower emissions, but outside European coverage, the transition is slower, and LNG maintains a presence in segments where it retains an economic advantage.
The comparison between e-methanol and e-ammonia occupies a central part of the analysis. Although e-ammonia presents a lower production cost, the study calculates that both reach a practically equivalent levelized cost of use. The initial advantage of ammonia is offset by the higher costs associated with storage, logistics, and supply operations, as well as the needs linked to its toxicity, crew training, and the safety zones required during bunkering operations.
Renewable hydrogen constitutes the main economic variable for both fuels. According to estimates from GCMD and BCG, its cost represents between 54% and 60% of the levelized cost of use of both e-methanol and e-ammonia. By 2030, the report estimates costs of approximately $66 to $67 per gigajoule for both alternatives. By 2050, the growth in hydrogen production and the reduction of renewable electricity and electrolyzer costs would bring the levelized cost of both fuels to approximately $52 per gigajoule in the proposed scenario.
The baseline scenario considers a levelized hydrogen cost of approximately three dollars per kilogram in 2050. The study also tests what would happen if it fell to around two dollars. Under that assumption, coupled with a faster global decarbonization trajectory, methanol and ammonia would jointly reach 36% of the energy demand of the global fleet in 2050, 32 percentage points above the baseline scenario.
For e-methanol, there is also another component that does not affect e-ammonia: the cost of biogenic CO2 necessary as raw material. The report analyzes prices between $50 and $200 per ton. With a cost of $50, methanol would reach 23% of energy consumption and ammonia 14%. At $100, the split would approximate, with 22% for methanol and 20% for ammonia. With higher costs, the model shifts a larger share of consumption towards ammonia.
The trajectory of biomethanol constitutes another variable capable of modifying the scenario. In the baseline assumption, its production cost remains at $43 per gigajoule, about $850 per ton, throughout the period. Under those conditions, methanol consumption remains around 2% of the fleet's energy demand in 2050.
GCMD and BCG propose an alternative scenario in which the cost of biomethanol decreases from $43 per gigajoule in 2025 to $33 in 2050, equivalent to a reduction from approximately $850 to $650 per ton. Under this hypothesis, methanol consumption rises from 2% to 19% of the energy used by the fleet in 2050, and the share of dual-fuel methanol engines nearly doubles before 2035 compared to the baseline scenario.
The report relates this evolution to the possibility of biomethanol initially acting as a fuel to expand the base of compatible engines and subsequently facilitate the use of e-methanol without the need to replace installed technology on board. To reach the level of consumption proposed in this scenario, around 70 million tons of biomethanol would be needed annually by 2050, a figure lower than the 135 million tons of availability estimated for that year by the International Renewable Energy Agency and the Methanol Institute, according to the references used by the study.
Ethanol presents a different dependency, fundamentally linked to its regulatory classification. In the baseline scenario, its contribution reaches approximately 9% of energy consumption in 2050. However, when biofuels from food crops receive unfavorable treatment, the model reduces both ethanol consumption and that of first-generation drop-in fuels to practically marginal levels. The displaced consumption primarily shifts to VLSFO, VLSFO with carbon capture, and fossil LNG.
These cost differences also condition the order book for new vessels. The report notes that the competitiveness of a fuel in 2050 is not alone sufficient to determine its future utilization. There must first be a fleet equipped with engines capable of consuming it. With an economic lifespan for ships of between 25 and 30 years, investment decisions made during the current decade and the first half of the next will condition the available capacity by mid-century.
The same relationship applies to port infrastructures. GCMD and BCG differentiate between the possible evolution of liquid fuel supply, such as methanol and ethanol, and that of ammonia. Methanol and ethanol are comparatively easier to transport, store, and supply, so their availability in a port depends less on proximity to production centers. The report considers that this characteristic may allow established bunkering hubs to maintain part of their position through the import of fuel from producing regions.
The current major supply centers have, according to the analysis, factors such as maritime traffic, supplier networks, storage capacity, marketing markets, and regulatory experience. At the same time, the study contemplates the entry of other ports if they have a sufficient cost advantage for fuel or a captive demand that allows sustaining investments.
In this process, regular shipping lines can play a specific role in the early stages of methanol and ammonia adoption. Repeated calls and predictable schedules allow for concentrated demand, establishing long-term supply contracts, and providing greater certainty for developing bunkering facilities. Ships operating in tramp markets, on the other hand, present less predictable routes and greater difficulties in committing to supply in specific ports.
Ammonia may introduce deeper changes to this structure due to its transportation, refrigeration, handling, and safety requirements. GCMD and BCG identify two models of ports capable of participating in this market. The first corresponds to hubs linked to production centers with competitive costs, where the infrastructure associated with exports could also be used to supply fuel to the vessels. The second corresponds to large importing ports with high maritime traffic and the capacity to concentrate demand.
In these import hubs, maritime demand could be combined with that from nearby industrial or energy facilities. This aggregation would allow for larger-scale purchases of ammonia, support investments in import terminals, and establish long-term supply contracts. The study uses various global hubs as examples in its analysis, including Singapore, Fujairah, the Amsterdam-Rotterdam-Antwerp area, and several Asian ports.
The model does not identify a single fuel as dominant in 2050 nor does it consider that the transition will focus on a single type of port. Among the variables that the report itself proposes for monitoring are the regulatory decisions of the IMO, the evolution of biomethanol costs, hydrogen prices, and biogenic CO2 treatment and the regulatory treatment of biofuels derived from food crops.