E-methanol  is  a  viable  marine  fuel  that  all  owners  must  consider  now  for decarbonisation  from 2029.  Not  only  is  it  viable,  but  for  first  movers  who  generate surplus  compliance,  the  use  of e-methanol  can  both  zero  their  bunker procurement costs  and  be  cash  positive.  This  paper makes  the  case  for  e-methanol  on  EU routes from  2029  and  urges  companies  to  secure  it  now through  long-term  offtake agreements.  FuelEU  compliance  units  can  be  banked  starting  in  2029 for the second period in 2030, when emission reduction targets really start to escalate.

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Regulatory  Context  (Section  A): We  show  how  FuelEU  Maritime regulation,  with CO₂  penalties of ~€640/t  CO₂e  (10x  current  EU  ETS)  will  disrupt  the  industry, increasing  VLSFO  costs  by  55% by  2030  and  tripling  them  by  2040¹.  Unlike  prior “uniform”  penalties,  FuelEU  incentivizes  e-fuels early, allowing early adopters to halve compliance costs and gain a competitive edge over peers.

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Methodology  (Section  B): FuelEU’s  “early  mover”  e-fuel  multiplier  incentive  and  e-methanol’s low  carbon  intensity  mean  only  minimal  e-fuel  and  fewer  new  vessels are  needed.  E-methanol requires  only  3%  of  newbuilding  fleet  and  total  fuel  use for compliance  to  2033  versus  38%  for LNG.  Owners can also use pooling to even get paid by competitors for any overcompliance.

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Results  (Section  C): E-methanol procured  at  $1,300/t  is competitive in  all  scenarios and, depending  on available alternatives,  companies should  be willing  to  pay  up  to $1,800/t.  At $1,300/t,  e-methanol delivers  a similar  cost  to  using biomethanol or LNG at  spot  prices, even when compliance  is  not monetised,  but does  so  without the same  risk exposures.  When overcompliance is  monetised,  e-methanol  is  not  only multiples cheaper  than  all  other  fuel strategies, but in addition, the fuel pays for itself, generating additional income for the owner.

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Implications  (Section  D): companies  wishing  to  reap  these benefits  must  secure e-fuel  now. This  is  the  only  way  to  guarantee supply,  as  e-fuels  will  not  be available on  the  spot  market  in the volumes  required.  Nearly  all  e-fuels  projects  operational in  2030 will  have  forward-sold  volumes years  in  advance  to  secure finance.  While long  term  fuel commitments  are  new  to shipping, owners  now  need  to develop fuel  strategies  alongside vessel  procurement.  Risks  have changed due  to  rising penalties and  green  fuel  shortages,  so  fuel procurement  strategies  must change too.  Locking  in  e-methanol  at  up  to  ~$1,800/t  will still  leave  the  owner  better  off than  paying  the penalty. Further, if compliance is monetised, the fuel can become an income generator.

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Risks (Section E): We explore alternative pathways and their risks. For example, compliance through LNG would require replacing 38-55% of a fleet by 2030, with penalties applying from 2035. Relying on biofuels is impossible and would require shipping to absorb 60% of global biofuel production within six years, amid high competition from road and air transport and increasing supply constraints. We assess the option to wait for e-fuel costs to fall before committing, and conclude that this is unlikely to beat moving now and leveraging the multiplier.

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Execution (Section F): We help owners with due diligence guidelines for assessing e-fuels projects. Access to cheap renewable power is critical, as power drives ~70% of e-methanol’s cost. Beyond cost, ensuring a project’s maturity, regulatory compliance, and technical viability is essential to minimise the risk of fuel no-show and non-compliance penalties.

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Conclusion (Section G): While a multi-fuel environment is expected, the core of effective portfolio management is diversification. Irrespective of base case assumptions, a diversified fuel strategy - which includes securing early and long term access to e-methanol - will provide the owner with flexibility and optionality, significantly improving their resilience to the future.

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1. Based on fuel costs for a 100mt/day vessel, assumes no increase in oil or EU ETS prices

A. Regulatory context: FuelEU Maritime incentivizes early adoption of e-fuels

Starting in 2024, EU ETS imposes a cost per tonne of CO2 emitted by each vessel, based on the ETS market price. FuelEU Maritime begins in 2025 and sets greenhouse gas (GHG) emission intensity reduction targets on a fleet basis that increase every five years. Like ETS, FuelEU offers a 50% discount for voyages to/from the EU, while intra EU voyages incur full penalty.  However, FuelEU differs from ETS in that it considers the emission intensity level of owners’ fleets on a well to wake basis, in contrast to the ETS tank to wake measurement of individual ships. LNG is relatively less attractive under FuelEU as its carbon intensity increases by significantly more than other fuels under well to wake measurement.

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There are four key components to FuelEU Maritime:

1. GHG intensity target: imposes a significant penalty for non-compliance

Under FuelEU, every ship greater than 5,000 GRT that burns VLSFO on an EU voyage will not be compliant from 2025. The penalty for non-compliance is €2,400/mt VLSFOeq, applied on every non-compliant tonne of fuel used.  This equates to a CO2 price of €640/tCO2eq or €58.5/GJ VLSFO consumed - 10 times the current EU ETS price.   By 2040, fuel costs for a 100 mt/day VLSFO ship will nearly triple due to penalties - and will increase by 55% as soon as 2030.

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Table 1: FuelEU Maritime GHG intensity targets

2. “RFNBO”means renewable liquid and gaseous fuels of non-biological origin. For a fuel to be classified as RFNBO, it must be derived fromrenewable non-biological sources, typically using renewableelectricity as its primary energy input (RED Art. 2.36)

3. Pooling mechanism - incentivises over compliance

FuelEU penalties are applied at fleet level, allowing overcompliance from one ship to offsetnon-compliance from others through a pooling arrangement, which may include other owners. This setup enables the trading of compliance units, with prices set by bilateral agreements. In theory, a non-compliant owner should be willing to pay up to the €2,400/tonne penalty for each compliance unit. This creates a strong incentive for those with access to e-fuels to generate surplus compliance—especially when leveraging the RFNBO 2x multiplier.

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4. RFNBO sub-quota further incentivizes use of e-fuels

Currently, there is no RFNBO quota for marine fuels, but FuelEU introduces a pathway to establish one. If the marine sector’s use of e-fuels on European routes remains below 1% by 2031, a 2% e-fuels sub-quota will be mandated from 2034. A 1% share would require ~840,000 tonnes of e-methanol to be used annually, based on current EU marine fuel consumption. The penalty for non-compliance will be the cost difference between e-fuels and fossil fuels at that time. For example, if spot prices were $525/tonne for VLSFO ($12.8/GJ) and $1,400/tonne for MeOH ($70.4/GJ), the penalty would be $57.6/GJ, applied to the shortfall between the 2% target and the actual e-fuel consumption per fleet. The pooling mechanism applies to the RFNBO quota as well, allowing overcompliance to be distributed across vessels.

B. Methodology: Calculating the costs of different decarbonisation strategies

‍To assess the economic impactof these regulations, we compare six decarbonisation strategies foran 8,000 TEU container vessel operating on intra-EU voyages:

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1. VLSFO only
2. VLSFO + LNG using dual-fuel vessel, 2-stroke diesel engine, slow speed e.g. MEGI
3. VLSFO + LNG using dual-fuel vessel, 2-stroke Otto engine, slow speed e.g. XDF³
4. VLSFO + B30 biodiesel blend
5. VLSFO + Bio-methanol⁴ using methanol dual-fuel vessel
6. VLSFO + E-methanol using methanol dual-fuel vessel

We use a 15-year time period (a typical fixed-price tenor requested by e-fuel developers for offtake contracts) starting in 2029 (the first year credits can be banked for the second compliance period, and a reasonable assumption for an offtake start date for e-fuels projects currently under development).  We consider the purchase price of the vessel and the costs of its operation. This allows us to calculate the total cost of ownership (TCO) resulting from each fuel decarbonisation strategy, across the 15 year period:

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1. Operational costs
2. Vessel capex (vessel, engines, tanks, fuel supply system)
3. The cost of purchasing the fuel itself
4. Vessel opex ex-fuel (port charges, canal fees, insurance, crew, maintenance)
5. Regulatory costs
6. EU ETS cost associated with use of a particular fuel mix
7. FuelEU Maritime GHG intensity penalty from use of a particular fuel mix
8. FuelEU Maritime RNBO compliance penalty

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We use fuel cost assumptions as follows:

1. Spot prices for VLSFO ($525/mt), LNG ($700/mt or $15/MMBtu) and B30 biodiesel blend ($820/mt)
2. Bio-methanol price of $1,000/mt and e-methanol price of $1,300/mt (based on prices we would expect competitive bio-methanol and e-methanol projects to be able to bear)
3. We also run two sensitivities
4. B30 price $984/mt, +20% versus spot to reflect likely future biofuel shortages
5. LNG price $18/MMBtu,  +20% versus spot in line with historical trends

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We then consider four fuel strategy scenarios, as follows.

Scenario 1: Total Cost of Ownership for a “compliance only” strategy

In this case, the fleet owner only buys enough green fuel to meet FuelEU compliance requirements and then uses VLSFO for the rest of their energy requirements. The share of alternative fuel required across a fleet to avoid penalties is outlined below:

3. While ~30% of the industry’s LNG vessel orders are based on MEGA engines with 3.1% methane slip, we use the default emission factor for XDF engines with 1.7% methane slip in our calculations given that the MEGA with 3.1% methane slip offers no CI reduction and would not even comply during the first compliance period.
4. Biomethanol is methanol produced from biomass via either gasification or by co-feeding biomethane from anaerobic digestion into a reformer-based methanol plant.

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GHG_VLSFO is 91.4 gCO2eq/MJ, GHG_alt,fuel and GHG_target over time are shown in Table 2.

Table 2. Percentage of alternative fuel required across a fleet to comply with the Fuel EU GHG intensity target - assuming the rest of the fuel mix consists of VLSFO - for different fuel options

As shown in Table 2, the low carbon intensity of e-methanol means that (a) an asset built today will survive through the entire FuelEU compliance cycle and (b) compliance can be achieved with very small volumes before scaling up (e.g., 3.4% green fuel up to 2033). This also means less capital is needed for new vessels. For instance, 2030 compliance can be achieved with e-methanol by replacing only 3 out of 100 ships, while meeting the target using LNG diesel vessels would require replacing 38% of a fleet. As such, an owner can scale into their position, with a few dual-fuelled e-methanol ships in 2030 before slowly adding more ships in future as their existing fleet is scrapped. A big bang, new fleet is not required.

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Scenario 2:  Total Cost of Ownership where overcompliance is monetised

Scenario 1 does not factor in a shipowners’ ability to monetize overcompliance. However, it is widely expected that many companies will elect to pay compliance penalties until e-fuel use scales up, making overcompliance monetization lucrative for those with surplus credits. In this scenario therefore, we assume an owner uses 100% alternative fuel and sells overcompliance. The price for a tonne of compliance will be set through commercial agreements, but for this analysis, we assume the buyer pays €2,000/t, a 17% discount to the full €2,400/t penalty.

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Scenario 3: Fuel cost for dual-fuelled methanol vessel in a “compliance only” strategy

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Scenario 4: Fuel cost for dual-fuelled methanol vessels monetising overcompliance

Scenarios 1 and 2 compare total cost of ownership for different fuel strategies, to inform owners considering both vessel and fuel investments. However, hundreds of dual fuelled methanol vessels have already been ordered⁵ - and for these owners who have already made the vessel capital investment, the decision on which fuel to procure should be evaluated differently.  

To that end, in Scenarios 3 and 4, we compare only the fuel costs of different strategies for a dual-fuelled methanol vessel (here, capex and non-fuel opex are the same for all strategies).

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5. Maritime Executive: ‘DNV calculates there are now a total of 269 methanol-fueled vessels on order for delivery’

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C. Results: Even in conservative scenarios, e-methanol is competitive at  ~$1,300/t, but when overcompliance is monetised, owners get paid to use it

The conclusions of our analysis can be summarised as follows:

1. E-methanol at $1,300/t is competitive in all scenarios. It delivers a similar cost to biomethanol or LNG at spot prices when compliance is not monetised, but does so without the same risk exposures (see Section E. for detail on LNG and biomethanol risks)
2. When overcompliance is monetised, e-methanol is not only multiples cheaper than all other fuel strategies, but a shipowner who has invested in methanol dual fuelled vessels can also get paid to buy  e-methanol at any price under $1,362/t

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Table 3: Key cost outputs for the ‘VLSFO only’ and ‘e-methanol at $1,300/mt’ cases in Scenario 1

In Scenario 1, the LNG MEGI (diesel cycle) engined vessel offers the lowest cost, with the B30 blend coming in second. The cost of using e-methanol at $1,300/t is only 1% higher than using LNG, and e-methanol breaks even with LNG at $1,195/t. Owners unable to use LNG or procure biofuels should pay up to $1,788/t for e-methanol instead of using VLSFO

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6. Includes fuel costs, EU ETS costs, and Fuel EU compliance costs. Equivalent per mtVLSFO cost assumes fuel consumption is 24,194 mtVLSFOeq/year. Equivalent per TEU cost assumes 152,000 TEU p.a. Based on 20 voyages per year and a 95% utilisation rate.

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Figure 2 - Scenario 1: Total cost of ownership for a “compliance only” strategy

In Scenario 2, where a shipping company sells overcompliance, e-methanol is ~60% cheaper than the next best option - an LNG MEGI diesel vessel - at a price of $1,300/t.

Figure 3 - Scenario 2: Total cost of ownership where overcompliance is monetised

In Scenario 3, where a methanol dual fuel vessel has already been purchased, under a “compliance only” strategy, e-methanol is the cheapest option at prices under $1,250/t - assuming biofuels could be procured at spot prices - unlikely by 2030.  More likely, e-methanol is cheaper than the next best alternative biomethanol, at prices under $1,422/t.

Figure 4 - Scenario 3:  Fuel cost for dual-fuelled methanol vessel in a “compliance only” strategy

In Scenario 4, where a shipping company sells overcompliance, e-methanol is the cheapest option under $1,803/t.  Most interestingly, the fuel generates income at any price under $1,362/t - suggesting that there could indeed, be such a thing as a free lunch when it comes to e-fuels.

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Figure 5 - Scenario 4:  Fuel cost for dual-fuelled methanol vessels monetising overcompliance

In conclusion, even without monetisation of overcompliance units, shipping companies should be willing to pay at least $1,300/t for e-methanol. Those unable to transition much of their fleet to LNG should be willing to pay over $1,800/t.  And for those able to procure e-methanol at $1,300/t and monetise overcompliance, the fuel is essentially an income generator. These economics are driven by the early mover RFNBO multiplier, which makes e-methanol significantly cheaper from 2029-33, effectively subsidising the rest of the 15-year period.

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D. Implications: A more strategic approach to fuel procurement is required

Our analysis indicates that, even without monetizing overcompliance, shipping companies should be able to pay $1,300 to $1,800/t for e-methanol from 2029-2043. Many e-methanol projects aim to price within this range, but few have secured offtakes. A key hurdle is the need for early, fixed price, long-term (10+ year) purchase commitments due to the lack of a liquid e-fuels market.⁷

E-fuels projects take 6+ years to develop, with significant funding needed during detailed engineering, ~4-5 years before production. To attract this capital, developers need committed buyers offering fixed long-term pricing well ahead of first molecule delivery. Given the nascency of the market and high upfront development costs, e-fuels must be pre-sold, leaving little for spot sales. While a liquid market may eventually emerge, this is likely over a decade away.

Whilst the industry is used to spot or short term procurement of bunkers, this simply must change to enable e-fuel developers to secure funds and develop their sites. Owners need to secure their e-fuels at the time at which they order their ships, otherwise they will be left behind. As this paper articulates, there is a significant first mover advantage to using e-methanol - but this advantage cannot be exploited unless the fuel is secured.

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With rising CO2 penalties, owners must secure green fuel to remain competitive and until there is a spot market for the product, early and long term commitments will be essential.

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Most companies agree that “doing nothing” is not an option, yet the industry largely remains in “wait and see” mode. Many owners feel that it is safer to defer action until there is more clarity. We see significant risk in this approach and believe the situation is more certain than it appears:

1. Doing nothing is not an option given the size of FuelEU penalties (see Section A)
2. Fossil LNG offers compliance but at best only until 2035 (2030 for most engines) and for those without existing vessels, the required capital investment is substantial
3. Compliant biofuels are unlikely to be available at competitive prices for the 2030 compliance period due to increasing supply constraints and competition
4. E-fuels will not be widely available on a short-term basis until the 2040s, as projects reaching the market prior will have pre-sold most volumes to secure financing.
5. Waiting until 2035 is a poor risk-return trade-off. Penalties are high and RFNBO subsidies decrease from 2034, raising e-fuels costs overall. By 2030, competition for e-fuels will also intensify as targets rise across sectors and late actors scramble to comply.
6. The risk-reward trade-off of committing early is significantly positive: at worst, locking in e-methanol at prices up to ~$1,800/t is preferable to paying penalties; at best, monetising overcompliance turns the fuel into an income generator.

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In sum, shipowners aiming to use e-fuels within the next decade must act now. Given the timelines for e-fuels development, securing fuel for 2029 requires commitments in 2025. Some shipowners, like MOL with its investment in e-fuels producer HIF Global⁸ and Maersk with its long-term bio-methanol offtake with LONGi⁹, have already anticipated the green fuel shortage and are taking steps to move ahead of the pack. While shipping traditionally invests in assets with 20+ year lifecycles, the industry is unused to long term fuel procurement. Now though, the two purchase decisions are linked - owners will need to develop, in parallel, their fuel procurement strategies for the vessels they order, at the time they negotiate these orders.

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7. LNG provides an interesting parallel - while the first commercial LNG plant began operating in the 1960s, a truly liquid and competitive market only began to take shape 40-50 years later in the early 2000s.
8. https://www.mol.co.jp/en/pr/2024/24108.html
9. https://maersk.com/news/articles/2024/10/30/maersk-signs-long-term-methanol-sourcing-deal

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E. Risks: Where could we be wrong?

To stress test our analysis, we consider a number of potential risks to our view.

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Could LNG plug the gap?

While LNG, especially at current low prices, offers an attractive near-term decarbonization option, its large-scale adoption faces several challenges.

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1. Significant investment in new fleet is required to meet even 2030 targets: LNG provides at best ~15%10 reduction in emissions versus VLSFO. However, to meet FuelEU’s 2030 6% fleetwide GHG intensity reduction, an owner would need to replace 40% of their fleet with LNG vessels:  15% GHG intensity reduction x 40% of fleet = 6% overall fleet GHG intensity reduction. To meet the 2035 target of a 15% reduction, the entire fleet would need to be LNG. Yet, by 2040, a 30% reduction is required, making fossil LNG non-compliant within just 10 years of purchasing new LNG ships. Further, last mile logistics are also expensive - a 20,000m3 LNG bunkering vessel for example can cost upwards of $80m. This makes LNG a challenging investment, especially for those who have not yet adopted it.
2. Non-compliant from 2035: Even on modern LNG vessels with engines like MEGI and XDF, auxiliary engine emissions are often underestimated. These engines are 4-stroke Otto cycle and have higher methane slip rates in the region of 3.1%. These engines contribute 15-30% of total LNG consumption, so their impact on the vessel's overall GHG intensity is significant. For example, using Fuel EU default emission factors, the GHG intensity reduction of a MEGI-powered LNG vessel drops from ~16% (main engine only) to ~11% when auxiliary engine consumption is included—meaning that 55% of the fleet would need LNG engines to comply by 2030, with all vessels facing penalties by 2035.
3. Methane emissions: Over a 100-year life cycle, methane is 28 times more harmful to the environment than carbon dioxide. LNG’s true carbon intensity is worsened by methane emissions during production, processing, and transportation, which are not currently reflected in EU standards. Pressure is mounting to include these emissions, and the default emission factors currently use a 100-year global warming potential for methane, underestimating its near- and medium-term climate impact. Even a conservative 2% emission rate adds ~33 gCO₂eq/MJ to LNG’s GHG intensity, making it worse than VLSFO. The International Council on Clean Transportation advises policymakers to consider a 6% emission rate, while Cornell University recently estimated the GHG footprint of U.S.-exported LNG at 160 gCO₂eq/MJ—33% higher than coal11. This measurement risk casts serious doubt on the LNG business case.
4. Challenges with Bio-LNG and e-LNG: While some suggest LNG ships could eventually transition to bio-LNG or e-LNG, bio-LNG shares the same feedstock limitations as other biofuels. Additionally, producing e-methane (for e-LNG) requires 10-15% more green hydrogen per GJ than e-methanol, not including liquefaction losses. As green hydrogen is the primary cost driver of e-fuels, e-LNG will inherently always be more expensive.
5. Price volatility: Although today’s LNG prices seem attractive, they have historically been highly volatile and often much higher. As illustrated in Section C, if LNG prices rise by just ~20% above spot, e-methanol becomes cheaper at $1,425/mt. Additionally, the correlation between LNG and oil prices limits LNG’s diversification benefit.‍

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10. Actual emission intensity ranges depending on the ship and engine type - 15% is used here as a reasonable estimate for illustration, based on the Fuel EU default well-to-wake emission factor for LNG (diesel cycle, slow-speed) of 76.2gCO2e
11. https://scijournals.onlinelibrary.wiley.com/doi/10.1002/ese3.1934

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Figure 8: LNG prices 2022-2024. Source: NGI’s Daily Gas Price Index, Bloomberg, CSI

In summary, while fossil to e-LNG may make sense for those who have already invested in LNG vessels, for those who haven't, an LNG strategy requires significant investment, offers minimal near-term decarbonization and ultimately locks owners into higher long-term fuel costs.

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Could bio fuels plug the gap?

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The idea that there will be enough biofuels at current or even much higher prices to meet 2030 targets is not supported by the data.

1. 2022 global biofuel production was 109M tonnes of oil equivalent¹² - shipping used 280 kt
2. Shipping consumes ~300M tonnes of fuel (VLSFOeq) per year¹³ - biofuels were < 0.1%.
3. To achieve the low end of IMO ambitions (GHG reduced by at least 20% by 2030) with biofuels would require converting 29% of shipping’s 300M tonnes of fuel to biofuel¹⁴;
4. Shipping would need to go from using 0.2% of biofuel volumes to using 65%, in 6 years.

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Figure 6: Global biofuels consumption and global shipping fuel consumption over time

12. https://www.iea.org/reports/renewables-2023/transport-biofuels
13. https://www.zerocarbonshipping.com/
14. Assumes: (i)  energy consumption stays constant per IEA forecast https://www.iea.org/data-and-statistics/charts/energy-consumption-in-international-shipping-by-fuel-in-the-net-zero-scenario-2010-2030-2),  (ii) absolute CO2 emissions from shipping have been flat in the last 2 decades. A 20% reduction in international shipping emissions vs IMO’s 2008 figure is equal to c. 180 MtCO2/year, equivalent to 80 Mt/year of B100, assuming B100 has a CI of 30 gCO2eq/MJ. (IMO https://www.imo.org/en/ourwork/Environment/Pages/Fourth-IMO-Greenhouse-Gas-Study-2020.aspx)
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While increased demand for biofuels should in theory incentivize new supply, in practice biofuel production is constrained by feedstock availability. Despite strong policy support, for the last decade biofuel supply has grown consistently below 5% per year¹⁵.

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Figure 7: Due to feedstock constraints, biofuels have only grown 4% for the last decade – to meet 2030 targets, shipping would need biofuels supply to grow at 128% per annum

Producing 1 tonne of biodiesel from soybeans requires ~1.5 football pitches worth of arable land¹⁶, and under the EU’s revised Renewable Energy Directive regulation (RED III, beginning in 2025)¹⁷, biofuels that compete with food production are prohibited. A more sustainable alternative is to source waste oils like used cooking oil (UCO), but scaling this approach is logistically impossible. For example, the UCO from all 1,400 McDonalds in the UK would only produce about 5 kt of biofuel annually¹⁸.

Biofuels are also becoming more constrained due to stricter regulations, such as RED III. This places a 7% cap on first-generation biofuels (those based on food/feed crops) and limits their eligibility for counting toward renewable energy targets¹⁹ with a particular focus on Indirect Land use Change (ILUC). Since first-generation biofuels still make up the majority of the supply, these restrictions will have a significant impact—only 22% of EU biofuel supply is second-generation.²⁰  Additionally, the Union Database for biofuels will make certification harder, further constraining supply. The EU also recently imposed a legally binding 1.7% transport-wide cap on UCO-based biofuels by 2030.²¹

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15. https://ourworldindata.org/grapher/biofuel-production
16. https://www.researchgate.net/figure/Comparison-of-estimated-production-and-land-use-requirement-from-various-biofuel-crops_tbl1_258403483
17. The Renewable Energy Directiveis the EU’s overarching legislation to promote renewable energyuse. RED II was adopted in 2018 and is currently in force. RED III isset to begin in 2025, introducing higher targets and strictersustainability criteria.
18. https://savart.com/blog/mcdonalds-fuels-trucks-with-recycled-cooking-oil-a-sustainable-move/
19. REDIII regulation,Article 26 (page 52): “theshare of biofuels consumed in transport, where produced from food andfeed crops, shall be no more than 7% of final consumption of energyin the transport sector”.
20. UsedCooking Oil as biofuel feedstock in the EU, CE Delft (2021)
21. REDIII regulation,Article 27 (page 54): “Theshare of biofuels and biogas produced from the feedstocks listed inPart B of Annex IX in the energy content of fuels and electricitysupplied to the transport sector shall be limited to 1.7%.”

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Finally, increased demand for biofuels is not limited to shipping: the EU has set a target of 29% share of renewables in transport by 2030, aviation has a 6% sustainable aviation fuel (SAF) consumption quota by 2030 under ReFuelEU²², and 19 non-EU countries also have biofuel demand incentives. For example, the 45Z tax credit in the U.S. is driving up demand for used cooking oil and HEFA-SAF, most of which will be imported.

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The IEA forecasts 47 million tonnes of global biodiesel production by 2028, an 18% increase from today. Shipping would need all of this production to meet even the low end of IMO 2030 ambitions, up from just 0.1% of global biofuel use today - an unrealistic shift over just six years.

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Could gasification plug the gap?

Biomass gasification has been promoted as a low-cost method to produce green methanol. However, despite decades of attempts, biomass gasification has never proven commercially viable due to the challenges of processing heterogeneous feedstock. Additionally, methanol produced this way would not qualify as a RFNBO, as the energy is derived from biological sources, making it ineligible for multipliers or quotas. Numerous gasification projects have faced setbacks, reflecting the ongoing cycle of unfulfilled promises in advanced biofuels. Technologies like cellulosic ethanol, woody biomass gasification, and algae-based biofuels have been "5 years away" since cleantech 1.0, yet none have reached commercial scale.

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Table 4. Gasification plants and challenges

Could cheap supply from China plug the gap?

China has strong ambitions in e-methanol production but lacks the feedstock advantages of other regions. Firstly, Chinese producers will face challenges meeting RED certification standards²³

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22. ReFuelEUAviation regulation,Annex I (page 29):“Shares of SAF – From 1 January 2030, each year a minimum shareof 6% of SAF”.
23. To claim benefits under EU regulations such as Fuel EU, biofuels and e-fuels must be certified by 3rd parties in accordance with the EU’s sustainability criteria. Certification involves detailed assessments of the fuels’ lifecycle carbon intensity - feedstock sourcing, fuel production, distribution, use - and impacts on food security, land use, and biodiversity.

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which require extensive historical data (25+ years) on land use and compliance with electricity feedstock rules such as hourly matching and additionality²⁴.  Relying on Chinese biofuel supply is also problematic. Earlier this year, the EU Commission reported that much of the used cooking oil entering Europe was fraudulently labelled palm oil, an unsustainable feedstock linked to deforestation²⁵. This led to the EU imposing a 36%²⁶ tariff on Chinese biofuels in August 2024  and announcing additional certification measures to stop fraudulent imports - the same concerns are likely to apply to the validity of biogenic CO2 and electricity used to produce Chinese e-fuels.

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Secondly, cheap renewable power is the most important feedstock for e-fuel cost competitiveness, and China does not have strong renewables. Inner Mongolia, China's top area for renewables, has solar capacity factors of ~20% and wind capacity factors of ~30-40%, similar to "good" renewables regions like Spain but below "great" regions like Texas. This is crucial, as renewable power costs make up ~70% of e-fuel production costs and are they key factor in e-fuel competitiveness.   On top of these hurdles, geopolitical factors, such as western import tariffs²⁷ and policies prioritising local energy production, will further complicate Chinese exports.

What if e-fuels become cheaper over time?

One argument against securing e-fuels before 2030 is the expectation that production costs will drop as technology improves, potentially making it more cost-effective to wait. While we agree that efficiency gains are likely, several issues challenge this view.

First, e-fuel production costs would need to fall significantly to offset the costs of paying the penalties and missing the pre-2034 RFNBO multiplier. As shown in Figure 9, waiting until 2035 to use e-methanol would require a price of $1,100/tonne to break even, compared to starting at $1,300/tonne in 2029. However, the Maersk McKinney Møller Center estimates e-methanol costs at $1,150 by 2035, suggesting a 15% reduction is unlikely. When overcompliance is monetized, the "wait and see" approach is even less favourable, even with a $1,100 price.

Second, while the most competitive projects may achieve lower production costs by 2035, demand for e-fuels is expected to surge due to higher FuelEU Maritime targets, rising EU ETS prices, potential IMO targets, and increased demand from other sectors. Thus, lower production costs will not necessarily translate into cheaper fuel. Notably, even at $1,800/tonne, e-methanol remains more competitive than VLSFO.

24. Hourly matching and additionality are two criteria for e-fuel certification, where many facilities fall short. Hourly matching requires that the renewable energy consumed by the fuel production process is generated in the same hour. Additionality requires that the energy source employed for fuel production must come from a newly constructured facility dedicated solely to supplying energy for the manufacturing process.
25. EuropeanParliament– Fraudulent imports of used cooking oil.
26. S&PGlobal –EU imposes anti-dumping duties targeting cheap Chinese biodieselimports.
27. Reuters–China’s biodiesel producers seek new outlets as hefty EU tariffsbite.

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Figure 9: Comparison of costs for “act now” versus “wait and see” strategies
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F. Execution: Which e-methanol to buy?

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Many shipping companies feel overwhelmed by e-fuel developers offering low prices that often rise after initial interest. The key question to assess the real fuel cost is:

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“What is your renewable power price, and is this power secured?”

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Since power accounts for around 70% of the levelized cost of e-methanol, a project lacking access to cheap power will simply not be competitive. Cost advantages from other factors such as CO2 and logistics will always be minor in comparison to low-cost power.

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Further, due to the high penalty from potential non-compliance if the fuel does not materialise, due diligence is essential to ensure that e-fuel projects are assessed not just on cost, but also on maturity, compliance, and viability:

1. Maturity: Are legally binding agreements in place for feedstock (power, water, CO2)?
2. Compliance: Is the feedstock RFNBO or RED compliant, with certifications in place?
3. Viability: Is the technology proven, particularly if using newer methods like gasification? Have cost estimates and technical viability been verified by a qualified third party?

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Securing fuel that is low cost on paper but that does not materialise or meet compliance standards ultimately provides no benefit.

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G. Conclusion

The economic case for e-methanol as a marine fuel from 2029 is not just viable, but compelling, especially given the sharp rise in VLSFO costs due to EU regulation. Early adopters will benefit from lower compliance costs and - by monetising overcompliance - could procure fuel for free. In contrast, companies who delay risk being non-compliant and ultimately paying their competitors.

The decarbonization pathway is set to become increasingly disruptive, with FuelEU Maritime introducing penalties 10 times higher than current EU ETS levels. Companies need to act now to secure long-term fuel contracts, as e-fuels will be in short supply. Securing fuel in 2029 will necessitate making long term commitments in 2025. E-methanol offers significant advantages, as its low carbon intensity allows compliance with smaller amounts of fuel, reducing capital investment in new vessels and allowing an owner to replenish their fleet gradually over time.

FuelEU encourages early adoption through multipliers and overcompliance pooling/trading, providing a clear financial incentive for first movers. Shipping companies should secure e-methanol at $1,300 to $1,800/tonne, as alternative fuel options face scalability and emissions challenges.  These dynamics will only increase further with the introduction of IMO targets.

Biofuels are constrained by feedstock availability and stringent regulations under RED III, while LNG faces issues with high capital investment requirements, methane leakage and locking into higher fuel costs via an e-LNG end state. China's e-methanol ambitions, though promising, are hampered by geopolitical hurdles and difficulty meeting RED compliance.

As a result, shipping companies must rethink their procurement strategies, moving away from spot fuel purchases to long-term commitments for green fuels. Securing e-fuels early will provide risk mitigation and competitive advantage as future fuel markets remain uncertain and as liquid markets for e-fuels are unlikely to materialise in the next 10-15 years.

Who really knows though?

We realise that the end result will be a multi fuel environment, with some owners choosing methanol, some choosing ammonia and others just rolling the dice to see what happens.

A final argument, for e-fuels.

Analysts can model countless scenarios with different assumptions, but the core rule of successful portfolio management is diversification.  Portfolios that are diversified consistently outperform those that are not, and the same principle applies to fuel procurement. Access to multiple fuels - including e-methanol - offers valuable flexibility and the potential to capitalise on pricing differentials. Therefore, regardless of different base case assumptions, a diversified fuel strategy - which includes securing early and long term access to e-methanol - will always provide the owner with flexibility and optionality, significantly improving their resilience to the future.

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Thank you for getting this far.  If you would like to discuss how engaging early to secure e-methanol could be part of your decarbonisation strategy, please reach out to Felix Leworthy at felix.leworthy@et-fuels.com or +447470 245 939

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Annex 1 - ETFuels overview

We are an e-fuels producer on a mission to enable the Energy Transition at Hyperscale by becoming the leading producer of green fuels ‒ through a pioneering “behind the meter” model ‒ starting with e-methanol for the shipping, aviation, road fuels and chemicals industries.

We have a pipeline of seven e-methanol projects under development in Texas, Spain, Finland and the US Midwest, each set to produce at least 100,000 tonnes per annum of RFNBO compliant e-methanol. Our first project in Texas is expected to reach commercial operations in 2029, with the rest of the pipeline set to follow closely behind.

Our team brings extensive experience across the hydrogen value chain, from power generation to regulatory frameworks, with a track record that includes developing over 10 GW in renewables, industrial-scale methanol and ammonia production, raising billions of dollars for infrastructure projects, managing the P&L and risk exposure for the world’s largest capsize shipping operator, and drafting EU green fuel legislation. As early movers in the e-methanol field, we have spent the past two years developing e-fuel facilities with leading OEMs and EPCs, conducting comprehensive engineering and procurement in both Europe and the US.

This track record gives us deep industry insights - backed by close engagement with investors and over 50 meetings with shipping customers - and has equipped us to understand the complexities of scaling these projects and transitioning to a sustainable, long-term fuel strategy. We’re committed to partnering with the marine industry to drive a swift and - crucially - economically viable path toward resilience and decarbonisation.

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Annex 2 - TCO calculator spreadsheet

The assumptions, calculations, and results presented in this note can be found in the accompanying ‘TCO calculator’ excel spreadsheet. The TCO calculator is set up to determine the total cost of ownership of a given decarbonisation strategy considering CAPEX, OPEX, fuel, and compliance costs over time. The spreadsheet is populated with default assumptions, but these can be overwritten by the user to test different scenarios. An overview of input assumptions is provided in the table below.

Calculations for the ‘compliance only’ scenarios (1 and 3 above) are shown in the ‘TCO_MeetCompliance’ tab. Calculations for the ‘over-compliance monetisation’ scenarios (2 and 4 above) are shown in the ‘TCO_MonetiseOvercompliance’ tab. In both cases:

1. Users can change the desired decarbonisation strategy and other input assumptions (orange cells) in rows 48-68.
2. For the user-specified assumptions, rows 86-109 calculate the economic and compliance metrics over time: fuel consumption, GHG intensities, EU ETS exposure, Fuel EU compliance balance, etc.
3. Rows 112-121 calculate total annual costs, and rows 124-134 determine the net present cost for the 15-year period between 2029 and 2043.

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The key difference between the ‘compliance only’ and ‘over-compliance monetisation’ scenarios lies in the share of alternative fuel that is consumed, represented by the values in row 101.

In the ‘compliance only’ scenario, the share of alternative fuel is reverse-engineered such that the fleet-wide GHG intensity meets or gets as close as possible to the target, and such that the compliance penalty is minimised. This is done using the following formula:

For each decarbonisation strategy, the above formula is evaluated in the ‘Tbl_AltFuelShare’ tab and used to determine the required share of alternative fuel over time. The results are summarised and used as a look-up table for use in row 101 in the ‘TCO_MeetCompliance’ tab.

In the ‘overcompliance monetisation’ scenario, the share of alternative fuel is set as 100% for the full period of analysis.

Finally, the spreadsheet includes a macro that allows users to analyse multiple scenarios simultaneously. To run the scenario analysis:

1. Ensure the file is unblocked (right-click on the excel file and select properties; in the General tab, check the “Unblock” box at the bottom)
2. Enable macros
3. Specify the decarbonisation scenario and commodity price assumptions in cells E141-L148. These will overwrite cells D49-D56 for the purpose of the scenario analysis. The spreadsheet can run up to 8 scenarios.
4. Press the grey ‘Run scenario analysis’ button in cell G137.
5. Note that the macro will stop working if any structural changes are made to the spreadsheet (i.e., adding or removing cells / columns / row).