Per-fuel well-to-wake intensity: e-fuels (synthetic / Power-to-Liquid)

Background: e-fuels as the Power-to-X family

e-fuels are the Power-to-X family of marine fuels, where X is a downstream molecule (Liquid, Gas, Ammonia, Methanol, Methane, Diesel, Jet) synthesised from two universal inputs: renewable electricity and a carbon source that is either atmospheric CO2 or short-cycle biogenic CO2. The defining feature is that no fossil feedstock enters the supply chain at any stage. The carbon atom in an e-diesel or e-methanol molecule is recycled atmospheric carbon, not fossil carbon mobilised from the geological reservoir. The hydrogen atom is electrolytic hydrogen, not steam-methane-reformed hydrogen from natural gas. The energy that drives both the electrolyser and the synthesis reactor is renewable electricity, certified under the additionality rules of RED III, not grid electricity from a fossil-heavy mix.

The structural difference between e-fuels and biofuels treated in HVO, FAME and bio-LNG is that biofuels rely on biological feedstock (vegetable oil, used cooking oil, animal fat, manure, food waste, woody biomass), which is volume-constrained by the available agricultural and forestry land base and by the competition for that feedstock from road transport, aviation, heat and food. Estimates of sustainable biofuel supply for the marine sector cap out at 30 to 80 million tonnes of fuel-oil-equivalent per year by 2050 across all biofuel categories, against a global marine bunker demand of 250 to 350 million tonnes per year on a current trajectory. e-fuels are constrained instead by renewable electricity supply, which is a structurally larger pool, and by the rate at which DAC and biogenic CO2 capture infrastructure can be deployed. The two routes are complementary, not competitive: biofuels are the cheapest option for the next decade and saturate the available feedstock, e-fuels fill the residual demand from the mid-2030s onwards, and the IMO’s net-zero pathway assumes both are deployed at the maximum credible rate.

The five primary e-fuel grades for marine use are e-diesel (a paraffinic distillate equivalent to fossil MGO produced via Fischer-Tropsch synthesis), e-methanol (CH3OH equivalent to fossil methanol but produced from CO2 hydrogenation), e-LNG (synthetic CH4 produced via the Sabatier reaction, indistinguishable from fossil LNG once liquefied), e-ammonia (NH3 equivalent to fossil ammonia but produced from electrolytic hydrogen via Haber-Bosch), and e-hydrogen (the parent electrolytic hydrogen molecule itself, treated separately in /wiki/per-fuel-wtw-hydrogen). Each downstream molecule is a different choice of energy carrier with different storage, handling and engine-side characteristics, but the upstream production architecture is identical: renewable electricity drives an electrolyser to produce hydrogen, a CO2 source provides the carbon (zero CO2 in the e-ammonia and e-hydrogen cases), and a synthesis reactor combines the two into the target molecule.

The engine-side compatibility of each e-fuel grade is the same as the equivalent fossil grade. e-diesel runs in any compression-ignition engine certified for marine gas oil without modification, e-methanol runs in dual-fuel methanol engines such as the MAN B&W ME-LGIM treated in /wiki/per-fuel-wtw-methanol-grades, e-LNG runs in any LNG dual-fuel engine treated in /wiki/per-fuel-wtw-lng-otto-diesel, e-ammonia runs in the emerging ammonia dual-fuel engines such as the MAN B&W ME-LGIA treated in /wiki/per-fuel-wtw-ammonia-grades, and e-hydrogen runs in the fuel cell or hydrogen ICE architectures treated in /wiki/per-fuel-wtw-hydrogen. The shipowner therefore captures the GHG benefit by switching to a renewable supply of the same molecule, with no engine modification beyond the one already needed for the fossil version of the same fuel.

RED III RFNBO definition

The Renewable Fuel of Non-Biological Origin (RFNBO) is a category created by Article 2(36) of Directive (EU) 2018/2001 (RED II) and refined under Directive (EU) 2023/2413 (RED III). The definition has three operational elements. First, the energy content of the fuel must come from renewable sources other than biomass: renewable electricity from wind, solar, hydro (with constraints), geothermal, marine, or aerothermal. Second, the fuel must not be a biofuel or a biogas: it cannot be derived from agricultural, forestry, aquatic or animal feedstocks. Third, the fuel must achieve a GHG saving of at least 70 percent against the relevant fossil fuel comparator under Annex V of RED II as updated by RED III.

The 70 percent saving threshold is the binding lifecycle requirement. The fossil comparator for transport fuels is approximately 94 gCO2eq/MJ (the EF(F) value applied in RED III Annex V), so an RFNBO must deliver a lifecycle WtW intensity at or below approximately 28 gCO2eq/MJ to qualify. e-fuels produced with high-intensity grid electricity at the electrolyser stage routinely fail this threshold; e-fuels produced under the additionality, temporal and geographical correlation rules with direct-coupled wind or solar typically deliver 1 to 10 gCO2eq/MJ and clear the threshold by a wide margin.

The RFNBO definition extends to all fuels derived from renewable hydrogen, not only the hydrogen molecule itself. e-methanol synthesised from renewable hydrogen and atmospheric CO2 is an RFNBO. e-ammonia synthesised from renewable hydrogen and atmospheric nitrogen is an RFNBO. e-LNG synthesised from renewable hydrogen and biogenic CO2 is an RFNBO. e-diesel and e-jet synthesised from renewable hydrogen and captured CO2 via Fischer-Tropsch are RFNBOs. The category is the legal entry point for the FuelEU 2x multiplier, which doubles the compliance value of the bunkered energy when the fuel is RFNBO-certified.

The RFNBO definition explicitly excludes biofuels (HVO, FAME, bio-LNG, bio-methanol from biomass gasification), low-carbon hydrogen produced from natural gas with carbon capture (so-called blue hydrogen), and electrolytic hydrogen produced from non-renewable grid electricity. The latter exclusion is significant: a green-hydrogen molecule produced from a low-carbon nuclear-and-hydro grid (Norway, Quebec, France) does not automatically qualify as an RFNBO unless the dedicated renewable supply satisfies the additionality test. Pink hydrogen from nuclear electricity is excluded from RFNBO eligibility under the current RED III text, although the European Commission has signalled an intention to revisit this exclusion in the 2027 review of the directive.

Production architecture: electrolyser + CO2 source + synthesis

The universal production architecture for e-fuels has four stages. Stage one is the renewable electricity supply, certified under the RED III additionality, temporal and geographical correlation rules. Stage two is the electrolyser, which dissociates water into hydrogen and oxygen using the renewable electricity. Stage three is the CO2 capture step (skipped for e-ammonia and e-hydrogen), which provides the carbon atom from atmospheric or biogenic sources. Stage four is the synthesis reactor, which combines hydrogen with carbon (or with nitrogen for ammonia) into the target molecule.

The electrolyser is the most capital-intensive stage and the largest energy consumer. The three dominant technologies are alkaline electrolysis (AEL) at 60 to 70 percent stack efficiency on LCV basis, polymer-electrolyte-membrane (PEM) at 65 to 75 percent stack efficiency, and solid-oxide electrolysis (SOEC) at 75 to 85 percent stack efficiency. Commercial AEL units are deployed at up to 100 MW per stack (Sungrow, ThyssenKrupp Nucera), commercial PEM units at up to 20 MW per stack (Plug Power, Cummins, ITM Power, Siemens Energy), and commercial SOEC units at the 1 to 5 MW pilot scale (Topsoe, Sunfire, Bloom Energy). The system efficiency at the balance-of-plant boundary (rectifier, water-treatment, cooling, gas drying, compression) is approximately 5 percentage points lower than the stack figure.

The CO2 source is the second key choice. Direct Air Capture (DAC) extracts CO2 from atmospheric air at concentrations of approximately 420 parts per million using a sorbent or solvent loop, with the leading technologies being amine-based liquid solvents (Carbon Engineering at Stratos Texas, 1PointFive offtake) and solid-amine sorbents (Climeworks Mammoth Iceland, Heirloom California). DAC delivers truly atmospheric CO2 and is the gold-standard source under RED III, but the energy demand is high (approximately 1.5 to 2.5 MWh per tCO2 captured, plus 4 to 8 GJ of low-grade heat) and the capital cost is currently USD 600 to 1,200 per tCO2 with a target trajectory to USD 100 to 200 per tCO2 by 2035 if industrial-scale deployment proceeds.

Biogenic point sources provide CO2 from concentrated streams at biomass conversion plants: pulp mill flue gas (Liquid Wind FlagshipONE in Sweden), bioethanol fermentation off-gas (US Midwest, Brazil), waste-incineration flue gas with biogenic fraction, and anaerobic digestion off-gas. Biogenic CO2 from these point sources is treated as carbon-neutral under both MEPC.391(82) and RED III when the underlying biomass is sustainably certified. The energy demand for biogenic-source capture is materially lower than DAC (approximately 0.4 to 1.0 MWh per tCO2 plus 2 to 4 GJ of heat) and the capital cost is currently USD 50 to 150 per tCO2, which is one of the structural reasons the first wave of commercial e-fuel facilities is built around biogenic CO2 sources rather than DAC.

The synthesis reactor depends on the target molecule. Fischer-Tropsch reactors operate at 200 to 350 degrees Celsius and 20 to 40 bar over an iron or cobalt catalyst, methanol synthesis reactors operate at 230 to 280 degrees Celsius and 50 to 100 bar over a copper-zinc-aluminium catalyst, Sabatier methanation reactors operate at 250 to 400 degrees Celsius and 1 to 30 bar over a nickel or ruthenium catalyst, and Haber-Bosch reactors operate at 400 to 500 degrees Celsius and 150 to 300 bar over an iron-promoted catalyst. Each route has its own conversion efficiency, selectivity envelope, and downstream separation chain.

The aggregate energy efficiency from renewable electricity to the e-fuel molecule at the bunker manifold is approximately 40 to 55 percent for e-methanol, 35 to 50 percent for e-LNG, 30 to 45 percent for e-ammonia (which carries a substantial nitrogen separation and synthesis loss), 35 to 45 percent for e-diesel, and 65 to 75 percent for e-hydrogen at high pressure (without liquefaction). The energy penalty for liquefaction of e-LNG and e-hydrogen, treated in /wiki/per-fuel-wtw-hydrogen, reduces the e-hydrogen figure to approximately 45 to 55 percent. The first-principle implication is that approximately half to two-thirds of the renewable electricity invested in the chain is lost to thermodynamics before the molecule reaches the engine, and the ship’s engine then converts that molecule to shaft energy at 45 to 55 percent. The overall renewable-electricity-to-shaft-energy efficiency is therefore approximately 18 to 30 percent for e-methanol, e-LNG and e-diesel, and approximately 35 to 50 percent for e-hydrogen in a fuel cell.

Synthesis route 1: Fischer-Tropsch (e-diesel/jet/gasoline)

The Fischer-Tropsch (FT) synthesis is a 1925-vintage chemistry developed at the Kaiser Wilhelm Institute in Germany. The reaction converts a syngas mixture of CO and H2 into a spectrum of hydrocarbon chains, with the chain-length distribution governed by the Anderson-Schulz-Flory statistics and the catalyst choice. The two dominant catalyst families are iron-based catalysts (high water-gas-shift activity, suitable for syngas with low H2/CO ratio, lower selectivity to long chains) and cobalt-based catalysts (no water-gas-shift activity, suitable for syngas with high H2/CO ratio, higher selectivity to long chains and to diesel-range product).

For an e-fuel facility, the syngas is produced not from fossil feedstock but from electrolytic hydrogen and captured CO2. The CO2 is converted to CO via the reverse water-gas-shift (RWGS) reaction (CO2 + H2 to CO + H2O), and the resulting CO is fed with additional H2 to the FT reactor. Alternative routes include direct CO2-FT chemistry on copper-modified catalysts (still at pilot scale) and the co-electrolysis route where SOEC produces a CO/H2 syngas mixture directly from CO2 and water (Topsoe, Haldor Topsoe Synthetic Aviation Fuel SAF-One). The downstream separation chain is the same as a conventional FT plant: the raw FT product is hydrocracked and isomerised to specification-grade diesel, jet kerosene and naphtha cuts.

The e-diesel product is a paraffinic distillate that meets the EN 15940 specification for paraffinic diesel and is fully compatible with ISO 8217 DMA and DMB marine distillate envelopes. The molecular composition is identical to fossil-derived FT diesel from a Sasol or Shell SMDS plant, and operators can use it in any compression-ignition marine engine without modification. The cetane number is high (typically 70 to 80, against 40 to 55 for fossil MGO), the sulphur content is below 5 ppm by construction, the aromatic content is below 1 percent, and the cold-flow behaviour matches Class A or Class B EN 15940. The e-jet product meets the ASTM D7566 Annex 1 specification for Fischer-Tropsch synthetic kerosene blend stocks and is the leading sustainable aviation fuel (SAF) pathway, with marine relevance as a co-product.

The MEPC.391(82) Annex 1 default for FT e-diesel from renewable electricity at less than 18 gCO2eq/MJ electrolysis input and DAC CO2 is approximately 3 to 8 gCO2eq/MJ on a WtW basis, which compares against a fossil MGO WtW of approximately 91 to 92 gCO2eq/MJ treated in /wiki/per-fuel-wtw-vlsfo-mgo. The variability reflects the renewable-electricity intensity at the electrolyser site, the CO2 capture energy demand, and the FT process energy. Commercial FT e-diesel and e-jet projects under construction or development include Norsk e-Fuel in Mosjoen Norway (target start 2026, 25 million litres per year, supply to Lufthansa and Norwegian aviation customers), Synhelion in Switzerland (solar-thermal syngas, target start 2027), Infinium in Texas (e-diesel and e-jet, partnered with Amazon and Brookfield), and Shell SkyNRG consortium projects in Rotterdam.

Synthesis route 2: Methanol synthesis (e-methanol)

The methanol synthesis chemistry combines hydrogen and carbon dioxide directly over a copper-zinc-aluminium catalyst (Cu/ZnO/Al2O3) at 230 to 280 degrees Celsius and 50 to 100 bar. The principal reaction is CO2 + 3H2 to CH3OH + H2O, with the secondary reverse-water-gas-shift reaction (CO2 + H2 to CO + H2O) and the methanol-from-CO reaction (CO + 2H2 to CH3OH) operating in parallel. The conversion per pass is limited by equilibrium to approximately 20 to 30 percent, so the reactor design relies on heavy recycle of unreacted gas, with a typical commercial loop returning 5 to 10 times the fresh feed before purge. The downstream separation chain is a standard distillation train that delivers IMPCA-grade or AA-grade methanol equivalent to the fossil product.

The methanol synthesis route is the most commercially mature e-fuel route at marine relevance. The chemistry is identical to fossil methanol synthesis from natural gas, the product is identical at the molecular level (CH3OH meeting the IMPCA Reference Specification treated in /wiki/per-fuel-wtw-methanol-grades), and the downstream bunker chain (existing methanol terminals, MAN ME-LGIM and WinGD X-DF-M dual-fuel engines, IGF Code methanol amendments) is already in place. The commercial advantage is that the molecule slots into an existing supply chain rather than requiring a parallel infrastructure build-out.

The MEPC.391(82) Annex 1 default for e-methanol from renewable electricity and biogenic CO2 is approximately 5 to 12 gCO2eq/MJ on a WtW basis, which includes the electrolyser energy, the synthesis energy, the CO2 capture energy, and the combustion CO2 (which is biogenic and treated as zero in the lifecycle balance under MEPC.391(82) and FuelEU Annex II). The TtW combustion CO2 is approximately 69 gCO2eq/MJ on a non-biogenic basis but is treated as zero on the WtW balance for sustainably certified e-methanol because the carbon was extracted from the atmosphere or from a short-cycle biogenic source. Compared with fossil grey methanol at a WtW of approximately 95 to 105 gCO2eq/MJ, the reduction is approximately 90 to 95 percent.

The leading commercial e-methanol projects in 2026 are HIF Global Haru Oni in Punta Arenas Chile (130,000 litres of e-methanol per year at pilot scale, scaling to 500,000 tonnes per year by 2027 under the HIF Patagonia and HIF Atacama plans), Liquid Wind FlagshipONE in Ornskoldsvik Sweden (50,000 tonnes per year, biogenic CO2 from the Övik Energi pulp-mill heat plant, target operations in 2026), Liquid Wind FlagshipTHREE in Sundsvall Sweden (target 2027), CIP and Maersk Catalyst Climate Centre for e-methanol production in Latin America and the US Gulf (target 2027 to 2028), European Energy Kassø in Denmark (32,000 tonnes per year, target 2026), and Topsoe and Aramco Vulcanol demonstration in Saudi Arabia. Maersk has signed letters of intent for several million tonnes per year of e-methanol offtake to fuel the dual-fuel container fleet from 2026 onwards.

Synthesis route 3: Sabatier methanation (e-LNG)

The Sabatier reaction combines hydrogen with carbon dioxide over a nickel or ruthenium catalyst at 250 to 400 degrees Celsius and 1 to 30 bar to produce methane and water (CO2 + 4H2 to CH4 + 2H2O). The reaction is exothermic at approximately 165 kJ/mol of CH4 produced and is thermodynamically favoured at lower temperatures, but the kinetics are slow at low temperature, so the reactor design balances temperature and conversion. The conversion per pass is high (typically 70 to 90 percent at one stage), and a two-stage reactor with intercooling can achieve 95 to 98 percent overall conversion. The downstream chain dries the product methane, removes residual CO2 and water, and feeds the gas to a small-scale liquefier to produce liquefied e-LNG.

The e-LNG product is methane (CH4) at greater than 99 percent purity, indistinguishable from fossil LNG once liquefied. The Wobbe index, the methane number, the LCV of approximately 50 MJ/kg, the density at minus 162 degrees Celsius of approximately 425 kg/m3, and the boil-off characteristics are all identical to fossil LNG. The vessel-side chain (IGF Code-certified gas-fuelled vessels with MAN ME-GI, WinGD X-DF, Wartsila DF dual-fuel engines, the LNG bunker terminal infrastructure, the boil-off management) is identical to the chain treated in /wiki/per-fuel-wtw-lng-otto-diesel. The drop-in characteristic for an LNG-ready vessel is the same as for bio-LNG.

The MEPC.391(82) Annex 1 default for e-LNG from renewable electricity and biogenic CO2 is approximately 4 to 10 gCO2eq/MJ on a WtW basis under the IMO LCA Guidelines, including the methane-slip term that applies to the engine cycle (1.7 to 3.5 percent for low-pressure Otto-cycle engines, less than 0.2 percent for high-pressure two-stroke diesel-cycle engines such as the MAN ME-GI). The methane-slip term is the dominant residual emission for e-LNG and is the principal reason e-LNG performs marginally worse than e-methanol on a WtW basis despite the lower carbon intensity of the molecule. The slip term is treated as fossil methane in the lifecycle accounting because the molecule is physically released to atmosphere regardless of the upstream origin, and the GWP100 of 28 (or GWP20 of 84) drives the slip contribution.

Commercial e-LNG projects are at smaller scale than e-methanol due to the methane-slip concern and the structural preference for e-methanol among container-line offtakers. Notable projects include Sunfire and Audi e-Gas in Werlte Germany (initially for road transport, now expanding to LNG bunker offtake), Tree Energy Solutions synthetic-methane import terminal in Wilhelmshaven Germany (target 2026, importing renewable methane from MENA region), and NextChem and Maire Tecnimont Power-to-Methane demonstration in Rome.

Synthesis route 4: Haber-Bosch (e-ammonia)

The Haber-Bosch process combines hydrogen and atmospheric nitrogen over an iron-promoted catalyst at 400 to 500 degrees Celsius and 150 to 300 bar to produce ammonia (N2 + 3H2 to 2NH3). The reaction is exothermic at approximately 92 kJ/mol of NH3 and operates with a recycle loop similar to the methanol synthesis loop, with conversion per pass limited by equilibrium to approximately 15 to 25 percent. The fresh nitrogen is supplied from a cryogenic air-separation unit (ASU) that operates at a parasitic energy cost of approximately 0.3 to 0.5 MWh per tNH3, which is small relative to the hydrogen-production stage but is non-trivial in the overall energy balance.

The e-ammonia product is anhydrous ammonia (NH3) at greater than 99.5 percent purity, indistinguishable from fossil ammonia at the molecular level. The product specification, the IGF Code amendments, the storage and bunkering chain, and the engine-side compatibility are treated in /wiki/per-fuel-wtw-ammonia-grades. The marine-engine pathway is the MAN B&W ME-LGIA ammonia dual-fuel two-stroke engine (commercial since 2024) and the WinGD X-DF-A ammonia dual-fuel engine (commercial since 2025), with Wartsila four-stroke ammonia engines under development.

The MEPC.391(82) Annex 1 default for e-ammonia from renewable electricity is approximately 3 to 9 gCO2eq/MJ on a WtW basis, with the variability reflecting the renewable-electricity intensity at the electrolyser site and the energy efficiency of the Haber-Bosch loop. The ammonia molecule itself contains no carbon, so the TtW CO2 from combustion is zero by chemistry. The non-zero contributions are the upstream electrolyser and synthesis energy demand on the WtT side, the small N2O term from incomplete combustion (typically 0.5 to 2 percent of the nitrogen, depending on engine design), and the ammonia slip term (typically 5 to 15 ppm in the engine exhaust on currently certified engines, equivalent to 1 to 3 gCO2eq/MJ at GWP100). The ammonia-slip term is regulatory-managed under MARPOL Annex VI Regulation 14 amendments under development at the IMO.

Commercial e-ammonia projects are concentrated in regions with abundant cheap renewable electricity and access to deep-water marine bunker chains. Notable projects in 2026 include the NEOM Helios Green Ammonia facility in Saudi Arabia (Air Products, ACWA Power, NEOM Company; 1.2 million tonnes per year of green ammonia from 4 GW of solar and wind, target export to Europe from 2026), Yara and JERA project in Western Australia (target 2026), the CWP Renewables AMAN consortium in Mauritania (target 2027), the Iberdrola Puertollano plant in Spain (target 2026), and the Aramco-Mitsubishi Yanbu demonstration in Saudi Arabia. The marine offtake chain is being developed in parallel by NYK, Mitsui OSK, K Line, MISC and AET Tankers for very-large ammonia carrier (VLAC) and dual-fuel chemical tanker fleet.

Direct Air Capture vs biogenic CO2 sourcing

The CO2 source for an e-fuel determines both the lifecycle intensity and the regulatory eligibility. Two source categories qualify for e-fuel use under MEPC.391(82) and RED III: atmospheric CO2 captured via Direct Air Capture (DAC), and biogenic CO2 from sustainably certified biomass conversion processes. Fossil CO2 from a coal or gas plant is conditionally eligible under early phasing rules but is being progressively excluded from RED III RFNBO eligibility from 2036, with a full exclusion expected from 2041 under the Commission Delegated Regulation (EU) 2023/1185.

Direct Air Capture (DAC) extracts CO2 from atmospheric air at the ambient concentration of approximately 420 ppm. The two leading process families are liquid-solvent DAC (Carbon Engineering with Stratos in Texas, partnered with 1PointFive and Occidental, target 500,000 tCO2 per year by 2026, scaling to 5 million tCO2 per year by 2030) and solid-sorbent DAC (Climeworks Mammoth in Iceland, 36,000 tCO2 per year operational since 2024, scaling targets to 1 million tCO2 per year by 2030; Heirloom California with calcium oxide chemistry; Global Thermostat). The energy demand is dominated by the desorption stage, which requires approximately 4 to 8 GJ of low-grade heat per tCO2 plus 1.5 to 2.5 MWh of electricity per tCO2. The capital cost in 2025 is approximately USD 600 to 1,200 per tCO2 of operating capacity, with a target trajectory to USD 100 to 200 per tCO2 by 2035 if industrial-scale deployment proceeds and learning curves match the trajectory observed for solar PV between 2010 and 2020.

Biogenic CO2 point sources provide concentrated CO2 streams at much lower capture cost. The leading sources for marine e-fuel chains are pulp-mill flue gas (the largest single biogenic CO2 source category in Europe; Liquid Wind FlagshipONE captures 70,000 tCO2 per year from the Övik Energi pulp-and-power complex), bioethanol fermentation off-gas (US Midwest corn ethanol plants emit approximately 35 to 40 million tCO2 per year of near-pure biogenic CO2 from fermentation, currently mostly vented; capture for e-fuel use is being deployed by Summit Carbon Solutions and Tallgrass for sequestration with an emerging e-fuel offtake market), waste-incineration plant flue gas with biogenic fraction (typically 40 to 60 percent biogenic), and large anaerobic digestion plants. The capture energy demand is approximately 0.4 to 1.0 MWh per tCO2 plus 2 to 4 GJ of heat, and the capital cost is currently USD 50 to 150 per tCO2.

The lifecycle treatment under MEPC.391(82) is symmetric for DAC and biogenic CO2: both are treated as zero-carbon-intensity inputs to the synthesis stage, with the upstream capture energy added to the WtT term. The RED III treatment is also symmetric in principle, but with a quota: a fraction of biogenic CO2 may carry a competing-use credit if the underlying biomass would otherwise be sequestered (forestry biomass, BECCS pathways), in which case the e-fuel attracts a partial debit. DAC is the gold-standard source under all current frameworks and is the only source that scales to the multi-gigatonne capacity required for global marine e-fuel demand without competing for biomass with food, feed, paper or sequestration uses.

The practical near-term reality is that biogenic CO2 from concentrated point sources is the cheapest and most readily available source for the first wave of commercial e-fuel facilities. The economic crossover where DAC becomes cheaper than biogenic capture depends on the DAC learning rate and on the future opportunity cost of biogenic CO2 (currently low because the capture infrastructure does not exist; rising as the CO2 commodity market matures). The IEA projects DAC and biogenic capture cost convergence in the 2035 to 2040 window if DAC scales as targeted.

MEPC.391(82) Annex 1 default WtW per pathway

The IMO MEPC.391(82) Lifecycle GHG Intensity of Marine Fuels Guidelines provide default emission factors per fuel and per production pathway, with the option to substitute a verified pathway-specific value when the producer maintains a recognised certification. For e-fuels, Annex 1 provides defaults across the four primary synthesis routes, with the values expressed in gCO2eq per MJ of fuel delivered to the bunker manifold (LCV basis).

For e-diesel from FT synthesis with renewable electricity at 0 to 18 gCO2eq/kWh and DAC or biogenic CO2, the Annex 1 default is approximately 3 to 8 gCO2eq/MJ on a WtW basis. The same fuel produced with grid electricity at 50 gCO2eq/kWh runs to approximately 30 to 45 gCO2eq/MJ and does not qualify as an RFNBO. With grid electricity at 250 gCO2eq/kWh (a coal-heavy grid), the WtW exceeds 100 gCO2eq/MJ and the fuel performs worse than fossil MGO.

For e-methanol from CO2 hydrogenation with renewable electricity and biogenic CO2, the Annex 1 default is approximately 5 to 12 gCO2eq/MJ on a WtW basis. With DAC CO2 instead of biogenic, the default rises by approximately 2 to 4 gCO2eq/MJ to reflect the higher DAC capture energy. Compared with the MEPC.391(82) Annex 1 defaults for methanol grades treated in /wiki/per-fuel-wtw-methanol-grades, the e-methanol value is materially below the fossil grey methanol default of approximately 95 to 105 gCO2eq/MJ and below the bio-methanol default of approximately 25 to 50 gCO2eq/MJ depending on biomass feedstock.

For e-LNG from Sabatier methanation, the Annex 1 default is approximately 4 to 10 gCO2eq/MJ on a WtW basis, with the methane slip term included on the IMO GWP100 basis. With a high-slip Otto-cycle engine the WtW rises to approximately 10 to 18 gCO2eq/MJ, and with a low-slip diesel-cycle engine (MAN ME-GI) it falls to approximately 4 to 8 gCO2eq/MJ. The slip term is the principal differentiator within the e-LNG category and is the structural reason e-methanol is preferred over e-LNG by container-line offtakers despite the lower-carbon source molecule.

For e-ammonia from Haber-Bosch with electrolytic hydrogen, the Annex 1 default is approximately 3 to 9 gCO2eq/MJ on a WtW basis. The N2O and ammonia-slip terms are included on the IMO basis, with N2O at GWP100 of 273 contributing approximately 0.5 to 1.5 gCO2eq/MJ depending on engine design. The MEPC.391(82) treatment of ammonia slip is under refinement at the IMO Sub-Committee on Pollution Prevention and Response (PPR), with provisional values applied in 2026 and a final methodology expected in 2027.

For e-hydrogen itself, the Annex 1 default is treated in /wiki/per-fuel-wtw-hydrogen at approximately 1 to 15 gCO2eq/MJ depending on the renewable-electricity intensity and the conditioning route (compressed CH2 versus liquid LH2 with the 35 percent liquefaction penalty).

The Annex 1 defaults are the fallback when a producer does not provide a verified pathway value. Producers operating under a recognised certification scheme (ISCC EU, RedCert, REDcert-EU, 2BSvs, RSB, REDISS) can substitute a pathway-specific value derived from the actual energy and material inputs at the production site. The pathway value is typically lower than the Annex 1 default because the default is conservative.

FuelEU Annex II RFNBO treatment + 2x multiplier (cross-link)

The FuelEU Maritime Regulation (EU) 2023/1805 Annex II provides default WtW emission factors for the same fuel categories covered by MEPC.391(82), with values aligned to the Commission Delegated Regulation (EU) 2023/1185 RFNBO methodology. For e-fuels, the FuelEU Annex II values are within 1 to 3 gCO2eq/MJ of the MEPC.391(82) Annex 1 values, with the small differences reflecting methodological choices on the upstream electricity treatment.

The FuelEU 2x multiplier is the operationally significant feature of the FuelEU treatment of e-fuels. Article 4(4) of Regulation (EU) 2023/1805 provides that the energy content of RFNBO fuels counts twice toward the FuelEU compliance balance for the period from 2025 to 2033, with a one-year transition window in 2034 before the multiplier sunsets. The multiplier doubles the compliance value of every megajoule of RFNBO-certified e-fuel bunkered, which means a vessel that bunkers 100 tonnes of e-methanol at 5 gCO2eq/MJ effectively delivers the same FuelEU compliance position as 200 tonnes of bio-methanol at the same intensity. The treatment is detailed in /wiki/fueleu-rfnbo-multiplier and modelled at /calculators/fueleu-rfnbo-multiplier.

The economic significance of the multiplier is large. At a FuelEU non-compliance penalty of approximately EUR 2,400 per tonne of GHG intensity above the trajectory (the Article 23 penalty calibrated against the EUR 2,400 / VLSFO-energy-equivalent rate), the implicit value of an RFNBO megajoule with the 2x multiplier reaches approximately EUR 60 to EUR 120 per tonne of e-fuel above the value of the same megajoule of bio-fuel without the multiplier. That premium is the principal demand-side support for the first wave of commercial e-fuel offtake contracts in 2026 and 2027, before the underlying production cost falls into the competitive range with bio-feedstock alternatives.

The certification chain required for the multiplier is the same as the RFNBO certification chain under RED III: an accredited certification scheme verifies that the renewable-electricity supply satisfies additionality, temporal correlation and geographical correlation, that the CO2 source is atmospheric or biogenic, and that the lifecycle GHG intensity satisfies the 70 percent saving threshold. The verification chain feeds the FuelEU MRV system through the bunker delivery note and the verifier’s certification statement.

The multiplier sunsets in 2034. After that date, RFNBO fuels count once toward the FuelEU compliance balance, the same as biofuels. The European Commission has signalled an intention to review the multiplier in the 2028 mid-term review of FuelEU and to consider an extension if the e-fuel supply has not scaled to meet the 2034 demand level. Operators planning multi-year offtake contracts should size the multiplier value carefully against the contract horizon.

RED III sustainability: additionality, temporal, geographical

The RFNBO sustainability framework under RED III is operationalised through three correlation rules in Commission Delegated Regulation (EU) 2023/1184: additionality, temporal correlation and geographical correlation. The three rules together ensure that the renewable electricity used to produce e-fuel is genuinely additional to the existing renewable supply rather than displacing existing renewable consumption to a fossil substitute, and that the renewable production is matched in time and space to the e-fuel synthesis.

Additionality requires that the renewable-electricity supply come from an asset that is new (commissioned within 36 months of the e-fuel production start), or that has not received public investment support. The rule prevents an e-fuel producer from claiming a renewable label on a wind farm that has been operating for ten years and feeding the grid at a fossil-displacing price; instead, the producer must contract with a new wind or solar asset that would not have been built absent the e-fuel offtake. The rule has a phase-in: until 2030, any renewable asset that receives no operating support qualifies, and from 2030 onwards the 36-month rule binds in full. The phase-in is a deliberate choice to allow the first wave of commercial e-fuel facilities to bootstrap the market without a hard renewables-asset constraint.

Temporal correlation requires that the renewable-electricity production be matched to the e-fuel production at a defined time resolution. From 2030 onwards, the rule is hourly correlation: each megawatt-hour of e-fuel-driving electricity must be matched to a megawatt-hour of renewable generation in the same calendar hour. Until 2030, the rule allows monthly correlation, which is materially looser. The hourly rule is controversial because the storage and curtailment economics on most grids do not deliver hourly matching at low cost without a dedicated battery system or a curtailment-tolerant electrolyser operating regime. Several producers have lobbied for an extension of the monthly window beyond 2030; the Commission has signalled no intention to relax the rule.

Geographical correlation requires that the renewable asset be located in the same bidding zone as the electrolyser, or in a directly connected bidding zone if the connecting transmission has spare capacity. The rule prevents an electrolyser in Germany from claiming a renewable label on a wind farm in Spain when the intermediate transmission is congested and the marginal MWh in Germany would come from coal or gas. The rule has exceptions for offshore wind in connected sea basins and for grid-island electrolysers in remote production hubs (NEOM Saudi Arabia, Pilbara Australia) where the grid topology supports direct attribution.

The three correlation rules together are the structural reason the RFNBO certification chain is more complex than the biofuel certification chain. A bio-LNG producer demonstrates feedstock origin and avoided-methane credit through ISCC EU mass-balance documentation; an e-fuel producer adds the three correlation tests on top of that, and the verification at every audit cycle requires hourly load and generation data, asset-age documentation, and grid-zone attribution. The compliance burden is substantial and is one of the structural reasons commercial e-fuel offtake prices are 30 to 60 percent above the underlying production cost.

Commercial pilots: HIF Haru Oni, Norsk e-Fuel, Liquid Wind, CIP/Maersk, Synhelion

The first wave of commercial e-fuel facilities reached operational status between 2022 and 2026, with production capacities of 50,000 to 500,000 tonnes per year and offtake contracts targeted at the marine, aviation and road-transport sectors.

HIF Global Haru Oni in Punta Arenas Chile started e-methanol and e-gasoline production at pilot scale in 2022. The facility uses 3.4 MW of wind-powered electrolysis, atmospheric CO2 captured by Carbon Engineering equipment, and a Topsoe methanol synthesis loop. The pilot capacity is approximately 130,000 litres of e-methanol and 350 tonnes of e-gasoline per year, with the first commercial product shipped to Porsche AG for racing fuel. The HIF Patagonia commercial expansion targets 500,000 tonnes per year of e-methanol from a 1.7 GW wind farm by 2027. The HIF Atacama project in northern Chile targets 1.5 million tonnes per year by 2030, with offtake contracts under negotiation with several container lines and aviation operators.

Norsk e-Fuel in Mosjoen Norway is a consortium of Sunfire (electrolyser), Climeworks (DAC CO2), Paul Wurth and Valinor that is building a 25 million litres per year e-jet and e-diesel facility. The facility uses a SOEC co-electrolysis route to produce syngas directly from CO2 and water, followed by Fischer-Tropsch synthesis and product upgrading. Target start of operations is 2026, with the entire offtake committed to Lufthansa and the Norwegian aviation sector, and a portion targeted at marine offtake from 2027.

Liquid Wind FlagshipONE in Ornskoldsvik Sweden started construction in 2023 and is targeting operations in 2026 with a 50,000 tonnes per year e-methanol facility. The CO2 source is the Övik Energi pulp-mill heat plant, which captures approximately 70,000 tCO2 per year of biogenic CO2. The renewable electricity comes from the Swedish hydropower grid and dedicated wind power purchase agreements. The follow-on FlagshipTHREE project in Sundsvall is at advanced engineering stage with target operations in 2027, and FlagshipFOUR through FlagshipTEN are in development across Sweden, Finland and the Baltic states. Liquid Wind has signed offtake contracts with Topsoe, Pertamina, and several container lines.

Copenhagen Infrastructure Partners (CIP) and Maersk announced the Catalyst Climate Centre in 2024 for e-methanol production in Latin America (Mexico, Brazil) and the US Gulf Coast, with target capacities of 1 to 3 million tonnes per year combined and target operations in 2027 to 2028. The renewable electricity comes from new wind and solar assets co-located with the e-methanol plant; the CO2 sources are a mix of biogenic and DAC. The offtake is dedicated to the Maersk dual-fuel methanol container fleet, which reached 25 vessels in service by 2025 and is targeting 60 vessels by 2027.

Synhelion in Switzerland operates a solar-thermal syngas process that directly produces a CO/H2/CO2 syngas mixture from concentrated solar heat at 1,500 degrees Celsius, biogenic CO2 and water. The syngas is fed to a Fischer-Tropsch reactor to produce e-jet and e-diesel. The DAWN demonstration plant in Julich Germany started operations in 2024 at 250 litres per day; the SUN-to-LIQUID commercial-scale facility in Spain is in development with target start in 2027. Synhelion has signed offtake contracts with Swiss International Air Lines, Lufthansa Group, and SWISS-related marine cargo operators.

The aggregate operational e-fuel capacity in 2026 across all commercial facilities is approximately 100,000 to 300,000 tonnes per year. That is approximately 0.05 to 0.15 percent of the global marine bunker market (250 to 350 million tonnes per year). The trajectory implied by announced projects targeting 2030 is approximately 5 to 15 million tonnes per year, or 2 to 6 percent of marine demand. The IEA 2024 World Energy Outlook projects 5 to 15 percent of marine fuel demand by 2040 in the announced-pledges scenario, and 25 to 35 percent by 2050 in the net-zero-by-2050 scenario.

e-fuel cost forecast: 2025 to 2035 trajectory

The production cost of e-fuels in 2025 is in the band of USD 1,500 to 3,500 per tonne of fuel-oil-equivalent (foe), depending on the synthesis route, the electrolyser cost, the renewable-electricity price, the CO2 source, and the project geography. The components are approximately: renewable electricity at USD 30 to 80 per MWh (the largest cost component, accounting for 50 to 70 percent of total), electrolyser CAPEX amortisation at USD 200 to 500 per tonne, CO2 capture at USD 100 to 700 per tonne (DAC at the high end, biogenic at the low end), synthesis CAPEX and OPEX at USD 200 to 500 per tonne, and storage and transport at USD 50 to 150 per tonne.

The 2030 cost forecast under the IEA Announced Pledges Scenario is USD 1,000 to 2,200 per tonne, with the reduction driven by electrolyser cost reductions (the AEL learning rate of 18 percent per doubling and PEM at 12 percent per doubling project the 2030 cost at approximately USD 200 to 400 per kW from USD 600 to 1,200 per kW in 2025), renewable-electricity cost reductions (continued PV and wind LCOE reductions in good resource zones to USD 20 to 40 per MWh), and DAC cost reductions if the early-2020s installations achieve the projected learning curves.

The 2035 cost forecast under the same scenario is USD 800 to 1,500 per tonne, which is in the competitive range with biofuels in scarcity-priced markets. The forecast is conditional on three structural conditions: renewable electricity below USD 30 per MWh in good-resource project geographies, electrolyser CAPEX below USD 200 per kW for AEL and PEM technology, and DAC cost below USD 100 per tCO2 for purpose-designed atmospheric capture or biogenic CO2 below USD 50 per tCO2.

The competitiveness threshold against fossil bunker fuel depends on the carbon price applied. With FuelEU and EU ETS carbon costs at EUR 100 to 150 per tCO2 (the 2026 to 2027 range), the implicit fossil-MGO cost is approximately USD 800 to 1,100 per tonne plus carbon, against which an e-fuel at USD 1,500 to 2,500 per tonne with the FuelEU 2x multiplier carries a net premium of USD 200 to 800 per tonne. With a global-marine carbon price reaching EUR 200 per tCO2 by 2035 (the IMO GFS trajectory toward net-zero), the threshold falls and e-fuels become competitive on a non-multiplier basis. The IEA forecast of USD 800 to 1,500 per tonne by 2035 places e-fuels at the structural break-even with fossil-plus-carbon under the IMO Net-Zero Framework treated in /wiki/imo-net-zero-framework.

IEA 2024 outlook on e-fuel supply availability

The IEA World Energy Outlook 2024 (published October 2024) provides three scenarios for e-fuel supply availability in marine: Stated Policies Scenario (STEPS), Announced Pledges Scenario (APS) and Net Zero Emissions by 2050 Scenario (NZE). The three scenarios project e-fuel shares of marine bunker demand at structurally different trajectories through 2050.

Under the STEPS scenario (current and announced policies), e-fuel reaches approximately 2 to 4 percent of marine bunker demand by 2040, scaling to 8 to 12 percent by 2050. The trajectory is constrained by the absence of binding policy support beyond the FuelEU multiplier and the EU ETS, with the IMO GFI mechanism providing supplementary demand pull from 2027 onwards.

Under the APS scenario (announced country-level pledges and corporate commitments), e-fuel reaches approximately 5 to 15 percent of marine bunker demand by 2040, scaling to 25 to 35 percent by 2050. The trajectory is consistent with the announced commitments of Maersk, MSC, Hapag-Lloyd, ONE, CMA CGM, NYK and Mitsui OSK to operate dual-fuel new-build vessels with green-fuel offtake from 2026 onwards.

Under the NZE scenario (1.5 degree Celsius alignment), e-fuel reaches approximately 15 to 25 percent of marine bunker demand by 2040, scaling to 45 to 55 percent by 2050. The remainder of the renewable share is split between biofuels (at saturation), nuclear-powered shipping (small share), and direct electrification of short-sea and inland vessels. The NZE share for e-fuels reflects the structural constraint that biofuels saturate at 80 to 100 million tonnes per year of marine bunker supply, leaving the residual 200+ million tonnes per year demand to e-fuels and electrification.

The structural conclusion of all three IEA scenarios is that e-fuels are not optional for the IMO net-zero trajectory: they are structurally required to fill the residual demand after biofuels saturate. The policy implication is that the FuelEU multiplier, the IMO GFI mechanism, and the EU Hydrogen Bank funding are calibrated to bridge the cost gap during the 2025 to 2035 ramp-up window, with the expectation that production scale and learning curves deliver structural cost competitiveness from 2035 onwards.

Comparison with bio-feedstock fuels

The bio-feedstock alternatives to e-fuels are the marine-relevant biofuels: bio-LNG, HVO renewable diesel, FAME biodiesel, and bio-methanol from biomass gasification (treated within /wiki/per-fuel-wtw-methanol-grades). The trade-offs across the two families are structural and span cost, supply scale, infrastructure compatibility, and lifecycle outcome.

Cost: bio-feedstock fuels are currently the cheapest renewable option for marine. HVO from waste feedstock is approximately USD 1,400 to 1,800 per tonne in 2025, bio-LNG is approximately USD 1,200 to 2,500 per tonne, FAME is approximately USD 1,200 to 1,600 per tonne, and bio-methanol is approximately USD 600 to 1,000 per tonne (per /wiki/per-fuel-wtw-methanol-grades). e-fuels are USD 1,500 to 3,500 per tonne in 2025. The cost gap is closing across the 2025 to 2035 window as e-fuel learning curves bring production cost down.

Supply scale: bio-feedstock fuels are constrained by sustainable feedstock availability. Global biomass-derived marine fuel potential is approximately 30 to 80 million tonnes of fuel-oil-equivalent per year by 2050 across all biofuel categories, against marine demand of 250 to 350 million tonnes per year. e-fuels are constrained by renewable electricity supply, which is structurally larger (global renewable electricity capacity by 2050 is projected at 25,000 to 40,000 TWh per year, against marine demand of approximately 12,000 to 16,000 TWh per year on a renewable-electricity-input basis at the 30 to 50 percent efficiency band).

Infrastructure compatibility: bio-feedstock fuels are mostly drop-in (HVO into MGO engines, bio-LNG into LNG dual-fuel engines, bio-methanol into methanol dual-fuel engines), so the shipowner captures the GHG benefit without a capital expenditure on the asset. e-fuels are also drop-in into the same engine architectures: e-diesel into MGO engines, e-methanol into methanol dual-fuel engines, e-LNG into LNG dual-fuel engines, e-ammonia into ammonia dual-fuel engines. The infrastructure compatibility is therefore equivalent across the two families for the same target molecule.

Lifecycle outcome: e-fuels generally deliver a lower WtW intensity than bio-feedstock fuels at the same scale of production. e-methanol from renewable electricity and biogenic CO2 delivers approximately 5 to 12 gCO2eq/MJ, against bio-methanol from biomass gasification at approximately 25 to 45 gCO2eq/MJ. e-LNG delivers approximately 4 to 10 gCO2eq/MJ, against waste-based bio-LNG at approximately 20 to 30 gCO2eq/MJ. The lifecycle gap reflects the cleaner energy supply chain on the e-fuel side (renewable electricity at near-zero gCO2eq/kWh) versus the inherent farm-level and process-level emissions on the biofuel side.

Regulatory treatment: e-fuels qualify as RFNBOs and earn the FuelEU 2x multiplier; biofuels do not earn the multiplier. The regulatory premium for e-fuels under FuelEU is significant during the 2025 to 2033 multiplier window, narrowing significantly from 2034 onwards.

The structural conclusion is that biofuels are the cheapest near-term option and saturate the available feedstock supply at approximately 60 to 80 million tonnes per year of marine bunker demand. e-fuels fill the residual demand from the mid-2030s onwards and become the dominant renewable category by the late 2040s under any net-zero-by-2050 trajectory.

Renewable electricity price + DAC cost crossover

The economic competitiveness of e-fuels depends on two structural cost reductions: renewable electricity below approximately USD 30 per MWh, and CO2 capture cost below approximately USD 50 to 100 per tCO2 for the relevant capture pathway.

The renewable electricity price threshold of USD 30 per MWh is informed by the energy intensity of e-fuel production. An e-methanol facility consumes approximately 11 MWh of electricity per tonne of e-methanol produced (8 MWh for the electrolyser, 1.5 MWh for synthesis, 1.0 MWh for CO2 capture and balance-of-plant, with synergy losses). At USD 30 per MWh, the electricity cost contribution to the e-methanol production cost is USD 330 per tonne. At USD 50 per MWh (typical 2025 PPA pricing in good-resource zones), the contribution rises to USD 550 per tonne. At USD 80 per MWh (typical 2025 European grid price), the contribution rises to USD 880 per tonne, which alone exceeds the fossil-methanol production cost.

The threshold is being approached in good-resource project geographies. The 2024 PPA prices for new solar PV projects in Saudi Arabia (NEOM) achieved USD 13 to 18 per MWh, in northern Chile (HIF) approximately USD 22 to 28 per MWh, in Australia (Pilbara) approximately USD 25 to 35 per MWh, and in southern Spain (Iberdrola) approximately USD 30 to 40 per MWh. The first wave of commercial e-fuel facilities is therefore concentrated in these geographies because the underlying electricity cost is structurally below the European grid price by a factor of 2 to 4.

The DAC cost threshold of USD 50 to 100 per tCO2 is informed by the carbon-content of e-fuels. An e-methanol molecule contains approximately 1.4 tCO2 per tonne of methanol (the carbon atom in CH3OH at one mole per mole of methanol), which translates to approximately USD 70 to 140 per tonne of e-methanol at the threshold range. At the 2025 DAC cost of USD 600 to 1,200 per tCO2, the DAC contribution alone is USD 840 to 1,680 per tonne of e-methanol, which is the binding cost constraint for DAC-sourced e-methanol. Biogenic CO2 at USD 50 to 150 per tCO2 in 2025 is already at or below the threshold, which is why the first wave of commercial e-fuel facilities relies on biogenic CO2.

The threshold convergence is forecast for the 2030 to 2035 window if both renewable electricity and DAC cost trajectories materialise. The IEA NZE scenario projects renewable electricity at USD 20 to 35 per MWh in good-resource zones by 2030 and USD 15 to 25 per MWh by 2035, and DAC at USD 200 to 400 per tCO2 by 2030 and USD 100 to 200 per tCO2 by 2035. Under that trajectory, e-methanol production cost falls to USD 800 to 1,500 per tonne by 2035, in the competitive range with fossil bunker fuel plus carbon.

Net-zero advantage: no fossil feedstock

The structural advantage of e-fuels in any net-zero-by-2050 trajectory is the absence of fossil feedstock from the supply chain. A bio-methanol molecule, a HVO molecule, or a bio-LNG molecule all carry biogenic carbon, but the upstream chain typically involves diesel-fuelled feedstock collection, fossil-grid electricity at the conversion plant, and fossil-grid hydrogen at the hydrotreatment stage. The lifecycle WtW intensity is consequently 15 to 50 gCO2eq/MJ, which is a 50 to 80 percent reduction against fossil VLSFO at 92 gCO2eq/MJ but is structurally floor-bounded by the residual fossil contribution.

An e-fuel produced under the full RED III RFNBO criteria has no fossil contribution at any stage. The renewable electricity is from a new wind or solar asset that displaces fossil generation rather than competing with it. The CO2 is atmospheric or short-cycle biogenic. The hydrogen is electrolytic. The synthesis energy is renewable. The downstream transport can be on a renewable-electricity-powered or hydrogen-powered vehicle. The lifecycle WtW intensity reaches the 1 to 5 gCO2eq/MJ band under best-practice operating conditions, which is a 95 to 99 percent reduction against fossil VLSFO and is the lowest WtW intensity of any liquid marine fuel.

The net-zero pathway implication is that e-fuels are the only marine fuel category that scales to a residual WtW intensity below 5 gCO2eq/MJ at multi-megaton-per-year capacity. Biofuels saturate at 15 to 30 gCO2eq/MJ across the full feedstock spectrum because the upstream agriculture and forestry chain has unavoidable residual emissions. Direct electrification reaches near-zero on shore-side recharging but is volume-constrained to short-sea and inland vessels (less than 10 percent of marine demand). Nuclear shipping is at concept stage with no commercial deployment. The arithmetic of the IMO Net-Zero Framework therefore requires e-fuels to deliver the bulk of the residual emissions reduction beyond the biofuel saturation point.

The certification chain for net-zero-aligned e-fuels relies on the RED III correlation rules and the MEPC.391(82) verified-pathway methodology. Operators procuring e-fuels for net-zero portfolio commitments should verify the certification chain at every link: the renewable-electricity source asset and its commissioning date, the temporal correlation methodology (hourly from 2030), the geographical correlation, the CO2 source and its biogenic or atmospheric origin, the synthesis-plant energy balance, and the verified-pathway WtW intensity from the certification body.

Engine-side compatibility: e-diesel / e-methanol / e-ammonia

The engine-side compatibility of e-fuels is the same as the equivalent fossil fuel grade, with no engine modification required when switching from fossil to e-fuel. The compatibility is structurally important because it means the shipowner captures the GHG benefit by switching the supplied molecule, with no capital expenditure on the asset.

e-diesel is a paraffinic distillate that meets the EN 15940 specification and the ISO 8217 DMA and DMB marine distillate envelopes (with the same density caveat applied to FT-derived fuels treated in /wiki/per-fuel-wtw-hvo). Any compression-ignition marine engine certified for marine gas oil runs on e-diesel without modification: the four-stroke high- and medium-speed engines (Wartsila, MAN, Caterpillar, Yanmar), the two-stroke low-speed engines (MAN B&W S/L/G series, WinGD W and X series), and the auxiliary diesel generators. The cetane number of e-diesel is high (70 to 80) compared with fossil MGO (40 to 55), which delivers slightly lower NOx emissions and slightly higher engine efficiency. The sulphur content is below 5 ppm, well within the 0.10 percent ECA limit and the 0.50 percent global limit.

e-methanol is chemically identical to fossil methanol and runs in the MAN B&W ME-LGIM dual-fuel two-stroke engine and the WinGD X-DF-M dual-fuel two-stroke engine, both treated in /wiki/per-fuel-wtw-methanol-grades. Dual-fuel four-stroke methanol engines from Wartsila and MAN four-stroke arms are commercial. The pilot fuel is typically MGO at 5 to 8 percent of energy on the ME-LGIM and X-DF-M engines, which adds a small fossil residual to the WtW outcome but does not change the structural advantage of the e-methanol pathway.

e-LNG is chemically identical to fossil LNG and runs in any MAN ME-GI, WinGD X-DF, Wartsila DF, or four-stroke gas-fuelled marine engine treated in /wiki/per-fuel-wtw-lng-otto-diesel. The methane-slip behaviour is the same on the same engine, with the high-pressure diesel-cycle ME-GI delivering slip below 0.2 percent of energy and the low-pressure Otto-cycle X-DF and DF engines delivering slip in the 1.7 to 3.5 percent range.

e-ammonia is chemically identical to fossil ammonia and runs in the MAN B&W ME-LGIA dual-fuel two-stroke engine (commercial since 2024 with the first vessels delivered to NYK and Mitsui OSK), the WinGD X-DF-A dual-fuel two-stroke engine (commercial since 2025), and the emerging Wartsila and MAN four-stroke ammonia engines for auxiliary and medium-speed applications. The pilot fuel requirement on the ME-LGIA is typically 5 percent MGO at high load and up to 15 percent at low load. The N2O and ammonia-slip behaviour is the same on the same engine.

e-hydrogen runs in PEM or SOFC fuel cells (commercial at sub-megawatt scale, with Ballard, Plug Power, ABB and Hyundai Heavy Industries marine systems), or in hydrogen ICE engines (CMB.TECH Hydroville, MAN Energy Solutions hydrogen test engines, Cummins QSK19H). The architecture and pathway is treated in /wiki/per-fuel-wtw-hydrogen.

The drop-in characteristic for the same engine is the same as for the equivalent fossil grade. The shipowner therefore makes the engine-procurement decision once at new-build (or at major retrofit), and the fuel procurement decision is made independently and can switch from fossil to bio to e-fuel as supply and pricing dictate. The asset is fuel-future-proofed against the IMO Net-Zero Framework trajectory by selecting a dual-fuel engine architecture at new-build, regardless of which renewable fuel ultimately prevails.

IGF Code coverage

The IMO IGF Code (International Code of Safety for Ships using Gases or other Low-flashpoint Fuels) is the safety framework for marine fuels with a flashpoint below 60 degrees Celsius and for low-flashpoint gaseous fuels. The Code covers LNG (in force since 2017), and the IMO has developed amendments and interim guidelines for the additional fuels relevant to the e-fuel discussion.

The methanol amendments to the IGF Code were adopted by MSC.105(82) in 2022 and entered into force on 1 January 2024. The amendments provide a complete safety case for methanol and ethanol as marine fuels, including tank arrangement, fuel-supply system, gas-detection, ventilation, fire-fighting, and crew training requirements. The amendments apply equally to fossil methanol and to e-methanol because the fuel is molecularly identical. e-methanol bunker chains in 2026 operate under the methanol IGF amendments in EU and Korean ports, with progressive regulatory acceptance in Singapore, Shanghai and US Gulf ports.

The ammonia interim guidelines were adopted by the IMO Carriage of Cargoes and Containers (CCC) Sub-Committee in 2024 (MSC.1/Circ.1668) and provide a partial safety case for ammonia as a marine fuel. The full IGF Code amendments for ammonia are expected to enter into force in 2026 to 2027 following CCC and MSC adoption. The interim guidelines cover the toxicity envelope (ammonia is toxic at concentrations above 25 ppm in air over 8 hours and immediately dangerous at 300 ppm), the bunker arrangement (typically segregated from the engine room with a closed-loop bunker chain), and the crew safety equipment (gas detection, breathing apparatus, neutralisation showers).

The hydrogen interim guidelines are at earlier development stage and are treated in /wiki/per-fuel-wtw-hydrogen. The full IGF Code amendments for hydrogen are expected in 2027 to 2028.

The e-diesel product is a low-sulphur paraffinic distillate with a flashpoint of 60 to 80 degrees Celsius, above the IGF Code threshold. The fuel is therefore not subject to the IGF Code at all, and the MARPOL Annex VI and SOLAS rules applicable to MGO and gas oil cover the safety case in full. The drop-in IGF-Code-free characteristic is one of the structural advantages of e-diesel against alternative renewable fuels for vessels not equipped with low-flashpoint fuel systems.

EU Hydrogen Bank + Innovation Fund scale-up

The European Hydrogen Bank is a Commission-launched mechanism to support the production scale-up of renewable hydrogen and RFNBO derivatives within the EU. The Bank operates a competitive auction (Carbon Contracts for Carbon Markets, CRCM) under which RFNBO producers bid the lowest fixed-price subsidy per kilogram of hydrogen produced over a 10-year contract period, with the Commission awarding contracts to the lowest bids until the auction budget is exhausted. The first auction (closed in February 2024) awarded approximately EUR 720 million across 7 projects in Spain, Portugal, Norway, Finland and the Netherlands at clearing prices of EUR 0.37 to 0.48 per kg H2. The second auction (December 2024) awarded approximately EUR 1.2 billion at clearing prices of EUR 0.40 to 0.55 per kg H2. The Bank’s third auction in 2025 has a EUR 1.5 billion envelope, and the trajectory through 2030 implies EUR 8 to 12 billion of cumulative Bank funding for renewable hydrogen production.

The EU Innovation Fund is the EU’s principal financing instrument for low-carbon technology demonstration at commercial scale. Funded by EU ETS auction revenues at EUR 38 billion through 2030, the Innovation Fund provides large-scale grants (up to 60 percent of CAPEX) for first-of-a-kind facilities. Notable e-fuel awards include the Liquid Wind FlagshipONE project (EUR 50 million), the Norsk e-Fuel project (EUR 80 million), the Topsoe SOEC project (EUR 95 million), the HyFlexPower synthetic-gas demonstration in France (EUR 41 million), and several e-methanol and e-ammonia projects across the EU. The 2024 round committed EUR 4.8 billion across hydrogen, e-fuels, carbon capture and clean tech.

The complementary funding sources are the Just Transition Fund (regional support for fossil-dependent regions transitioning to renewable industries), the Cohesion Fund (cross-cutting infrastructure support), and the Recovery and Resilience Facility (national recovery plan funding for energy transition). The aggregate EU funding envelope for renewable hydrogen and e-fuel scale-up over the 2025 to 2030 window is approximately EUR 30 to 50 billion, equivalent to approximately 5 to 10 percent of the projected CAPEX requirement for the renewable hydrogen and e-fuel infrastructure target.

The non-EU policy support is significant in three jurisdictions. The United States Inflation Reduction Act provides the 45V hydrogen production tax credit at up to USD 3.00 per kg H2 for renewable hydrogen produced through 2032 with 10-year contract horizons, which is the largest single subsidy for renewable hydrogen globally and has driven announcements of 25+ million tonnes per year of US renewable hydrogen capacity. The Japanese Green Innovation Fund at JPY 2 trillion (USD 13 billion) supports hydrogen and ammonia value-chain demonstration. The Korean K-Hydrogen Roadmap at KRW 12 trillion (USD 9 billion) supports hydrogen import and ammonia production. The aggregate non-EU support is comparable to the EU envelope and is structurally important for the global supply build-out.

Formula, assumptions, and limits

Formula

The well-to-wake CO2-equivalent intensity of an RFNBO-certified e-fuel is the sum of the upstream production energy term, the carbon-source capture term, and the combustion (or slip) term. For an e-fuel produced from renewable electricity and atmospheric or biogenic CO2:

The combustion-CO2 term is treated as zero on the WtW balance because the carbon is atmospheric or short-cycle biogenic and is recycled within the relevant timescale. For green-electricity (DAC-CO2) production:

The blend formula for fossil bunker mixed with e-fuel at energy fraction $x_{\text{e-fuel}}$:

The FuelEU-effective intensity with the RFNBO 2x multiplier is:

Derivation

The WtW formulation follows the IMO LCA Guidelines treated in /wiki/marine-gfs-methodology, which decompose the lifecycle into a WtT stage covering all energy and material flows up to the bunker manifold, and a TtW stage covering combustion and slip from the moment the fuel enters the engine.

The WtT term for an e-fuel aggregates the renewable-electricity supply (with the lifecycle intensity of the wind turbine or solar panel manufacturing, the balance-of-plant, the transmission losses and the end-of-life), the electrolyser energy (50 to 55 kWh per kg H2 produced), the CO2 capture energy (1.5 to 2.5 MWh per tCO2 for DAC, 0.4 to 1.0 MWh per tCO2 for biogenic capture), the synthesis-plant energy (typically 1 to 3 GJ per tonne of e-fuel for methanol, FT, Sabatier, or Haber-Bosch), and any pipeline or truck transport between the e-fuel plant and the marine bunker barge.

The TtW combustion CO2 term is set to zero for sustainably certified e-fuels because the carbon was extracted from the atmosphere or from a short-cycle biogenic source. The combustion CO2 is still physically present in the funnel exhaust, but it does not appear on the GHG balance. For e-ammonia and e-hydrogen, there is no combustion CO2 term at all because the molecule contains no carbon.

The TtW slip term applies on different chemistries. For e-LNG, the methane slip from the engine is treated as fossil methane on the GWP100 basis at 28, contributing approximately 0.2 to 8 gCO2eq/MJ depending on engine type. For e-ammonia, the ammonia slip and N2O contribution apply at 1 to 4 gCO2eq/MJ on the IMO methodology. For e-methanol and e-diesel, the slip term is negligible.

Assumptions

1. Renewable electricity satisfies RED III correlation rules. The assumption is that the electricity is from a new asset (additionality), matched in time on an hourly basis from 2030 (temporal correlation), and located in the same bidding zone as the electrolyser (geographical correlation). Failure of any of the three rules invalidates the RFNBO classification and forfeits the FuelEU 2x multiplier.
2. CO2 source is atmospheric or sustainably biogenic. Fossil CO2 from coal or gas plants is conditionally eligible under early phasing rules but is being progressively excluded from RFNBO eligibility. e-fuels from fossil-source CO2 do not qualify for the FuelEU multiplier from 2036 onwards.
3. Lifecycle GHG saving threshold is met. The RFNBO classification requires a 70 percent saving against the EF(F) fossil reference of approximately 94 gCO2eq/MJ, so a lifecycle WtW intensity at or below approximately 28 gCO2eq/MJ.
4. Verified pathway documentation is in place. The default Annex 1 values are conservative; a producer with a verified pathway under ISCC EU, REDcert, RSB, REDISS, or RTRS can substitute a pathway-specific value, typically lower than the default.
5. Engine combustion factors are equivalent to fossil grade. e-diesel in compression-ignition engines, e-methanol in ME-LGIM and X-DF-M engines, e-LNG in dual-fuel gas engines, and e-ammonia in ME-LGIA and X-DF-A engines deliver near-identical TtW combustion factors to the fossil grades. The biogenic/atmospheric carbon treatment is the only reason the WtW differs.
6. Bunker delivered matches the certified specification. Mass-balance allocation requires that the physical bunker volume not exceed the documented RFNBO-input volume into the supplying terminal.

Worked example

A 16,000 TEU ultra-large container vessel fitted with a MAN B&W G95ME-LGIM dual-fuel methanol two-stroke engine takes a 1,000-tonne 100 percent e-methanol bunker in Rotterdam. The bunker is certified ISCC EU as RFNBO-compliant, sourced from a Liquid Wind FlagshipONE production with biogenic CO2 from the Övik Energi pulp mill and renewable electricity from a new Swedish wind farm.

WtT term: $7$ gCO2eq/MJ (verified pathway, includes electrolyser, synthesis, biogenic CO2 capture and Swedish renewable electricity) TtW combustion CO2 term: $0$ gCO2eq/MJ (biogenic, sustainably certified) TtW slip term: $0$ gCO2eq/MJ (negligible for methanol Otto-cycle) Pilot fuel residual: approximately $4$ gCO2eq/MJ (5 percent MGO pilot at fossil intensity, weighted into the bunker WtW at 0.05 weight) WtW total: approximately $11$ gCO2eq/MJ

Compared with the same engine on fossil grey methanol at WtW of 100 gCO2eq/MJ (per /wiki/per-fuel-wtw-methanol-grades), the e-methanol bunker delivers a reduction of approximately 89 gCO2eq/MJ, an 89 percent improvement. With the FuelEU 2x multiplier applied, the effective intensity for the 1,000-tonne bunker is half of the bunkered intensity for the energy-attribution calculation.

For 1,000 tonnes at an LCV of 19.9 MJ/kg, the energy is $1{,}000 \cdot 1{,}000 \cdot 19.9 = 19.9$ TJ, and the GHG saved on a WtW basis is $89 \cdot 19.9 \cdot 10^{12} \cdot 10^{-9} \cdot 10^{-3} = 1{,}771$ tonnes CO2eq versus fossil grey methanol. At a fossil-methanol bunker price of USD 700 per tonne and an e-methanol bunker price of USD 1,800 per tonne, the green premium for the 1,000-tonne lift is USD 1.1 million, equivalent to approximately USD 621 per tonne of CO2eq avoided before the FuelEU multiplier. With the multiplier applied, the effective compliance value is approximately doubled, bringing the implicit GHG cost down to approximately USD 310 per tonne of CO2eq, which is competitive with the FuelEU non-compliance penalty rate.

Edge cases and limits

Hourly temporal correlation failures from 2030. A producer relying on the monthly correlation regime through 2029 must transition to hourly from 1 January 2030. Producers with high-cost renewable PPAs and grid-balancing electrolysers may struggle with hourly matching at low cost. Operators should verify the producer’s hourly matching strategy in the offtake contract.

Pilot fuel residual on dual-fuel engines. The MGO pilot fuel on ME-LGIM, X-DF-M, ME-GI, X-DF, and ME-LGIA engines adds a small fossil residual to the WtW outcome (typically 2 to 6 gCO2eq/MJ at 5 to 8 percent pilot energy fraction). Operators targeting near-zero WtW should procure bio-MGO or e-diesel as the pilot fuel rather than fossil MGO.

DAC supply constraints in early years. DAC capacity is 0.04 million tCO2 per year operational in 2025, scaling to approximately 5 to 10 million tCO2 per year by 2030. e-fuel facilities targeting DAC CO2 from 2025 to 2030 may face supply allocation constraints. Biogenic CO2 from pulp mills and bioethanol fermentation is the alternative for the early ramp-up.

Methane slip on e-LNG. e-LNG WtW intensity is dominated by the engine-side methane slip term, which makes engine choice (high-pressure diesel-cycle ME-GI vs low-pressure Otto-cycle X-DF / DF) more important than upstream optimisation for the lifecycle outcome. Operators with low-pressure dual-fuel engines should consider e-methanol over e-LNG for the cleanest lifecycle.

Pink hydrogen exclusion under RED III. Electrolytic hydrogen from nuclear-powered electricity does not currently qualify as RFNBO under RED III. e-fuels produced from pink hydrogen (Iberdrola Bilbao demonstrations, Cernavoda Romania) cannot earn the FuelEU 2x multiplier despite delivering similar lifecycle intensity to green-hydrogen pathways. The Commission’s 2027 review of RED III may revise this exclusion.

Multiplier sunset in 2034. The FuelEU 2x multiplier expires in 2034, which materially reduces the regulatory premium for RFNBO offtake. Operators planning multi-year offtake contracts beyond 2033 should size the multiplier value carefully against the contract horizon.

Non-EU bunker ports without RFNBO certification. A vessel taking bunkers in Fujairah, Yokohama, or other ports outside the EU mass-balance area may receive an e-fuel product that is physically RFNBO but not RED III certified. Under FuelEU rules, the bunker is treated at the fossil default unless an equivalent verification is provided. Operators should verify the certification chain at the procurement stage.

Cost crossover not before 2030 to 2035. e-fuels at the 2025 cost band of USD 1,500 to 3,500 per tonne are not competitive with fossil-plus-carbon at current FuelEU and EU ETS prices on a non-multiplier basis. Operators relying on cost competitiveness for procurement should plan for the 2030 to 2035 crossover window and use the FuelEU multiplier to bridge the gap during 2025 to 2033.

Regulatory basis

• IMO MEPC.391(82): Annex 1 default emission factors for synthetic fuel pathways from renewable electricity and captured CO2, biogenic and atmospheric CO2 treatment as zero on the WtW balance, methane and ammonia slip defaults
• FuelEU Maritime (Regulation (EU) 2023/1805): Annex II default values for RFNBO fuels, Article 4(4) RFNBO 2x multiplier provision, mass-balance verification requirements
• RED III (Directive (EU) 2023/2413): Sustainability and 70 percent GHG saving criteria for RFNBO, Article 27 RFNBO definition, Annex V Methodology
• Commission Delegated Regulation (EU) 2023/1184: Additionality, temporal correlation (hourly from 2030), and geographical correlation rules for renewable hydrogen and derivatives
• Commission Delegated Regulation (EU) 2023/1185: RFNBO GHG calculation methodology for renewable hydrogen and synthetic derivatives, fossil reference EF(F) of 94 gCO2eq/MJ
• Commission Implementing Regulation (EU) 2022/996: Mass-balance verification rules, certification scheme recognition criteria
• MARPOL Annex VI: Sulphur content limits (0.5 percent global, 0.1 percent ECA), met by e-diesel at less than 5 ppm
• IGF Code (SOLAS Chapter II-1 Part G): Methanol amendments in force from 1 January 2024 (MSC.105(82)), ammonia interim guidelines (MSC.1/Circ.1668), hydrogen interim guidelines under development at CCC
• ISCC EU, REDcert, RSB, REDISS, 2BSvs: Voluntary certification schemes recognised by the European Commission for RFNBO compliance verification

Common errors

1. Counting TtW combustion CO2. A common error is treating the e-fuel combustion CO2 as non-zero. Under MEPC.391(82) and FuelEU Annex II for sustainably certified e-fuels with atmospheric or biogenic CO2 source, the combustion CO2 is zero on the WtW balance.
2. Treating e-fuel as automatically RFNBO-eligible. The RFNBO classification requires the additionality, temporal and geographical correlation tests on the renewable-electricity supply. An e-fuel produced with grid electricity at any intensity does not automatically qualify.
3. Confusing the FuelEU 2x multiplier with a CO2 reduction. The multiplier is an energy-attribution doubling under Article 4(4); the actual lifecycle CO2 saving against the fossil reference is the same regardless of the multiplier. The multiplier is a regulatory acceleration mechanism, not a physical reduction.
4. Assuming all biogenic CO2 sources are equivalent. Pulp-mill flue gas, bioethanol fermentation off-gas, and waste-incineration biogenic fraction have different capture costs, different verification chains, and different competing-use credits. The certification body verifies the source-specific accounting.
5. Treating pink hydrogen as RFNBO. Electrolytic hydrogen from nuclear electricity is excluded from current RED III RFNBO eligibility. e-fuels from pink hydrogen cannot earn the FuelEU 2x multiplier.
6. Counting fossil-CO2 e-fuels as RFNBO from 2036 onwards. The Commission Delegated Regulation (EU) 2023/1185 progressively excludes fossil-source CO2 from RFNBO eligibility from 2036, with full exclusion expected from 2041. Operators planning multi-year offtake contracts should verify the CO2 source eligibility against the contract horizon.
7. Ignoring the pilot-fuel residual on dual-fuel engines. The MGO pilot fuel on dual-fuel methanol, gas, and ammonia engines adds a 2 to 6 gCO2eq/MJ fossil residual that should be included in the bunker WtW assessment. Operators targeting near-zero WtW should specify a renewable pilot fuel.

See also

• /wiki/per-fuel-wtw-methanol-grades
• /wiki/per-fuel-wtw-ammonia-grades
• /wiki/per-fuel-wtw-hydrogen
• /wiki/per-fuel-wtw-bio-lng
• /wiki/per-fuel-wtw-hvo
• /wiki/per-fuel-wtw-fame
• /wiki/per-fuel-wtw-lng-otto-diesel
• /wiki/per-fuel-wtw-vlsfo-mgo
• /wiki/marine-gfs-methodology
• /wiki/fueleu-intensity-formula-breakdown
• /wiki/fueleu-rfnbo-multiplier
• /wiki/imo-net-zero-framework
• /calculators/fuel-wtw-efuel
• /calculators/fuel-wtw-blend
• /calculators/fuel-wtw-methanol
• /calculators/fuel-wtw-ammonia
• /calculators/fuel-wtw-hydrogen
• /calculators/fueleu-rfnbo-multiplier
• /calculators/fueleu-ghg-intensity
• /calculators/gfi-attained

Related calculators

• VLSFO - Well-to-Wake
• LPG - Well-to-Wake
• LNG - Well-to-Wake by engine pathway
• HFO - Well-to-Wake
• MGO / MDO - Well-to-Wake
• HVO / Renewable Diesel - Well-to-Wake
• FAME Biodiesel (B100) - Well-to-Wake
• Bio-LNG - Well-to-Wake

Related formulas

• fuel wtw efuel
• fuel wtw vlsfo
• fuel wtw nuclear
• fuel wtw mgo
• fuel wtw methanol
• fuel wtw lpg
• fuel wtw lng
• fuel wtw hydrogen
• Power Triangle - kVA / kW / kVAR