Per-fuel well-to-wake intensity: VLSFO and MGO

Background: VLSFO and MGO as the GFI baseline pathways

Conventional residual and distillate marine fuels still account for the majority of energy delivered to deep-sea shipping in 2026. Every quantitative greenhouse-gas (GHG) instrument that the industry now operates under, whether the IMO Net-Zero Framework adopted at MEPC 83, the FuelEU Maritime intensity cap, or the EU ETS surrender obligation, expresses its targets relative to the carbon footprint of these two fuels. VLSFO and MGO are therefore not merely two products on a bunker price screen; they are the empirical anchor points against which every alternative fuel pathway is benchmarked.

The IMO LCA Guidelines, codified in resolution MEPC.391(82) and refined through subsequent MEPC sessions, set out a uniform method for converting fuel volumes into WtW gCO2eq/MJ values. The same resolution provides Annex 1 default factors for each fuel pathway so that operators without certified actual values have a fall-back. For VLSFO and MGO, those defaults are intended to represent fleet-average residue and distillate streams from European, Middle Eastern, and Far Eastern refineries operating with conventional crude slates.

FuelEU Maritime, the EU’s lifecycle fuel standard, repeats the same construction in Annex II with values calibrated against the JEC (JRC-EUCAR-CONCAWE) Well-to-Wheels v5 dataset and CONCAWE marine fuel pathway studies. The numbers are slightly different from MEPC.391(82) because the methodological boundaries (allocation, scope of upstream methane, treatment of co-products) are not identical, but the order of magnitude and the VLSFO-vs-MGO spread are consistent.

The 2020 baseline of 91.16 gCO2eq/MJ that FuelEU uses is itself a fleet-weighted average dominated by VLSFO consumption in that year, with HFO above the IMO 2020 cap effectively gone from the merchant fleet outside scrubber-equipped tonnage. The IMO Net-Zero Framework, by contrast, expresses the Tier 1 required GFI against a similar reference but uses 93.3 gCO2eq/MJ as a representative starting point that more closely tracks an MGO-equivalent endpoint in the MEPC.391(82) defaults table.

The pages below walk through the ISO 8217 specifications, the refinery and combustion physics behind these defaults, and the operational consequences for bunkering, ECA switching, and BDN documentation.

ISO 8217 grade definitions

ISO 8217:2024 is the international standard for marine fuel specifications and is the contractual reference invoked in virtually every bunker supply agreement worldwide. It defines a residual table (RM grades) and a distillate table (DM grades), each with viscosity, density, sulphur, water, ash, and other quality parameters. VLSFO and MGO map onto specific grades within these tables.

VLSFO is not a single ISO 8217 grade; it is a market category that covers any residual marine fuel with sulphur not exceeding 0.50% m/m, which is the IMO 2020 global sulphur cap limit. In practice, most VLSFO supplied at major bunker hubs falls under RMG 380 (residual marine, max 380 cSt at 50 °C) with a sulphur cap re-flagged as 0.50% m/m, although RMG 180, RMD 80, and RMA 10 also appear in cargo lists. ISO 8217:2024 introduced a dedicated 0.50% sulphur category and tightened cetane index, sediment, and stability parameters following the operational instability incidents of 2020.

The density of typical VLSFO ranges from 0.93 to 0.99 kg/L at 15 °C, viscosity from 30 to 380 cSt at 50 °C, and pour point from 0 to 30 °C depending on paraffinic content. Carbon residue (Micro Carbon Residue, MCR) sits between 8 and 15 mass percent, ash below 0.10 mass percent, and asphaltene content from 2 to 12 mass percent.

MGO is a distillate marine fuel and falls almost exclusively under DMA or DMZ in ISO 8217. DMA (Marine Gas Oil A) is the conventional grade with sulphur up to 1.0% m/m for non-ECA service or up to 0.10% m/m for ECA operation. DMZ is similar but with a tighter viscosity floor (3.0 cSt minimum at 40 °C rather than 2.0 cSt) introduced to protect high-pressure fuel pumps in modern slow-speed engines from low-viscosity-induced wear. DMB (a blended distillate) and DMX (an emergency-use light distillate, sometimes carried for lifeboat or generator service) round out the distillate table.

MGO density typically lies between 0.85 and 0.89 kg/L at 15 °C, viscosity from 2 to 11 cSt at 40 °C, cetane index above 40, and ash below 0.01 mass percent. The fuel is essentially a refined gas oil similar to off-road diesel, with no residual fractions, no asphaltenes, and no measurable MCR.

The ISO 8217 grade matters for WtW accounting because the lower calorific value (LCV) used in the energy denominator depends on it: VLSFO at RM grade carries LCV near 40.5 MJ/kg, MGO at DMA or DMZ carries LCV near 42.7 MJ/kg, and the same kilogram of fuel therefore delivers approximately 5.4% more energy as MGO than as VLSFO. The TtW emission denominator scales accordingly.

Refinery production pathway and WtT component

Both VLSFO and MGO leave the refinery as products of conventional crude oil processing, but the production pathway and the cuts they originate from are different.

Crude oil arrives at the refinery via pipeline or VLCC tanker, undergoes desalting and atmospheric distillation in the crude distillation unit (CDU). Atmospheric distillation produces light naphtha, heavy naphtha, kerosene, light gas oil, heavy gas oil, and atmospheric residue. The atmospheric residue is then routed to vacuum distillation where it is split into vacuum gas oil (VGO) and vacuum residue.

MGO is essentially a marine-grade gas oil cut, drawn from the heavy-gas-oil and light-cycle-oil streams downstream of atmospheric distillation, occasionally with hydrotreating to meet sulphur and stability specifications. Where refineries are configured for ULSD (ultra-low-sulphur diesel) production, MGO is often a desulphurised stream blended down with kerosene or lighter cuts to hit the DMA viscosity envelope.

VLSFO is more complex. It is typically a blend of low-sulphur residual streams (vacuum residue from sweet crudes, atmospheric residue from low-sulphur crudes) with distillate cutter stocks (light cycle oil, vacuum gas oil) added to bring viscosity, cetane, and stability into the RMG specification. Some refineries produce VLSFO from desulphurised vacuum residue via residue hydrotreating or solvent deasphalting; others rely on crude-slate selection (e.g., West African or Brazilian sweet crudes) to hit the 0.50% sulphur cap without deep processing.

The WtT (well-to-tank) component of WtW intensity captures everything from crude extraction at the wellhead through refining, storage, and bunker barge delivery to the ship’s manifold. For both fuels, WtT typically runs 8 to 12 gCO2eq/MJ in the MEPC.391(82) and FuelEU defaults, with VLSFO sitting slightly lower than MGO on a per-MJ basis because residue carries less of the refinery energy burden than distillate streams under most allocation methods.

The WtT figure is sensitive to:

• Crude origin and the carbon intensity of upstream extraction (Saudi light versus Canadian oil sands diluted bitumen differ by 5 to 15 gCO2eq/MJ at the wellhead).
• Transport mode and distance from oilfield to refinery.
• Refinery configuration (hydroskimming versus deep conversion versus FCC) and the energy intensity per barrel of throughput.
• Allocation method between co-produced fuels (cut-off, mass, energy, system expansion).

Upstream extraction, transport, refining: per-step gCO2eq/MJ contributions

Disaggregating the WtT into its three principal phases gives the per-step picture used in the JEC v5 dataset and CONCAWE pathway studies.

Upstream extraction (crude production) typically contributes 3 to 6 gCO2eq/MJ for a global average crude slate. The figure includes drilling, primary and secondary recovery, associated gas handling (with or without flaring), produced water management, and field-level methane leakage. For sweet conventional crudes from the Middle East, the value is near the lower bound; for heavy sour crudes with steam-assisted gravity drainage or significant flaring, the upper bound is exceeded. The MEPC.391(82) default uses a global-weighted average of approximately 4 gCO2eq/MJ for petroleum-derived marine fuels.

Crude transport from oilfield to refinery contributes 0.5 to 1.5 gCO2eq/MJ. Pipeline transport over land is at the lower end; long-haul VLCC voyages (Gulf to Far East, West Africa to Europe) push the upper end. The default value embedded in Annex 1 is approximately 0.8 gCO2eq/MJ.

Refining is the largest WtT component, typically 3 to 7 gCO2eq/MJ depending on refinery configuration and product slate. A simple hydroskimming refinery with limited conversion produces VLSFO and MGO with a refining footprint near 3 gCO2eq/MJ; a deep-conversion refinery running coker, FCC, hydrocracker, and hydrotreater units to maximise distillate yield runs nearer 6 to 7 gCO2eq/MJ. The refining contribution depends heavily on the allocation methodology chosen (covered in Section 10), because residue and distillate share the same crude input but require different downstream processing.

Distribution and bunkering add a small terminal-storage and barge-delivery contribution, typically 0.3 to 0.8 gCO2eq/MJ. The default value is approximately 0.5 gCO2eq/MJ.

Summing these phases gives a typical WtT for VLSFO of approximately 9.0 gCO2eq/MJ and for MGO of approximately 10.5 gCO2eq/MJ in the MEPC.391(82) Annex 1 table. The MGO premium reflects the higher refining energy intensity per MJ of distillate product compared to residue.

TtW combustion CO2, CH4 slip, N2O

The tank-to-wake (TtW) stage covers everything from the ship’s bunker tank inlet to the funnel exhaust. For petroleum-derived fuels, the dominant contributor is direct CO2 from carbon combustion, with smaller contributions from methane slip and N2O formation in the engine.

TtW CO2 is calculated from the carbon mass fraction $C_f$ of the fuel, multiplied by 44/12 (the molecular mass ratio of CO2 to C) to convert carbon mass to CO2 mass, then divided by the energy delivered (LCV times fuel mass) to express as gCO2/MJ. For VLSFO with $C_f \approx 0.864$ and LCV 40.5 MJ/kg, the TtW CO2 figure is approximately 78 gCO2/MJ. For MGO with $C_f \approx 0.875$ and LCV 42.7 MJ/kg, the TtW CO2 figure is approximately 75 gCO2/MJ. MGO has a higher carbon fraction but also a higher LCV, so the per-MJ CO2 emission is slightly lower than VLSFO.

Methane slip ($CH_4$) is unburned methane passing through the engine to the exhaust. For petroleum-derived liquid fuels, slip is negligible because the fuel itself contains essentially no methane and combustion of liquid hydrocarbons does not produce significant unburned methane in conventional diesel combustion. MEPC.391(82) assigns a default $CH_4$ TtW contribution of approximately 0.00005 g/g fuel for both VLSFO and MGO, equivalent to less than 0.05 gCO2eq/MJ after GWP100 weighting at 28. The story is materially different for LNG and methanol fuels, where slip can dominate the TtW intensity.

N2O formation occurs during high-temperature combustion in the engine, with rates depending on combustion temperature, residence time, and excess-air ratio. For four-stroke and two-stroke marine diesel engines burning VLSFO or MGO, N2O TtW contribution is approximately 0.00015 to 0.00018 g/g fuel, equivalent to 0.9 to 1.2 gCO2eq/MJ after GWP100 weighting at 265. The default in MEPC.391(82) Annex 1 is approximately 1.0 gCO2eq/MJ for both fuels, with a small upward adjustment for low-load operation where combustion temperature regimes favour N2O formation.

Low-load and partial-load operation matters because port-stay and slow-steaming patterns push engines into operating envelopes where combustion efficiency dips, particulate emissions rise, and unburned hydrocarbon slip increases. For petroleum-derived fuels, the GHG impact of low-load operation is modest (typically 1 to 3 percent on TtW intensity), but the operational and air-quality consequences are larger.

Summing TtW contributions gives a typical figure for VLSFO of approximately 79 to 80 gCO2eq/MJ and for MGO of approximately 76 to 78 gCO2eq/MJ. MGO’s TtW intensity is lower than VLSFO’s on a per-MJ basis because of its higher LCV.

MEPC.391(82) Annex 1 default values

The Annex 1 default WtW emission factor table in MEPC.391(82) provides the fall-back values for operators that do not bring forward certified actual lifecycle data through a recognised certification scheme. The table is organised by fuel pathway, with separate rows for each combination of feedstock, conversion process, and end-use.

For VLSFO (residual marine fuel, sulphur ≤ 0.50%), the typical default WtW intensity is 91.0 gCO2eq/MJ, decomposing approximately as:

• WtT: 9.0 gCO2eq/MJ (extraction 4.0, transport 0.8, refining 3.7, distribution 0.5)
• TtW CO2: 78 gCO2eq/MJ
• TtW CH4: 0.05 gCO2eq/MJ
• TtW N2O: 1.0 gCO2eq/MJ

For MGO (DMA / DMZ marine distillate, sulphur ≤ 0.10% in ECA, ≤ 1.0% globally), the typical default WtW intensity is 93.3 gCO2eq/MJ, decomposing approximately as:

• WtT: 10.5 gCO2eq/MJ (extraction 4.0, transport 0.8, refining 5.2, distribution 0.5)
• TtW CO2: 75 gCO2eq/MJ
• TtW CH4: 0.05 gCO2eq/MJ
• TtW N2O: 1.0 gCO2eq/MJ

The 2.3 gCO2eq/MJ spread between MGO and VLSFO is dominated by the refining-stage allocation. Distillate fuels carry more of the refinery energy footprint per MJ produced because they require deeper hydrotreating and conversion than residue. The TtW per-MJ CO2 figure for VLSFO is slightly higher than MGO because VLSFO has a lower LCV; on a per-kilogram basis, MGO emits more CO2 per kilogram burned, but per MJ delivered it emits slightly less.

The defaults are designed to be conservative in the sense that they are intended to represent a fleet-average pathway and should not penalise operators who can demonstrate lower actual values through certified data. Operators wishing to use lower values must bring forward a recognised LCA certificate from an approved certification scheme.

FuelEU Annex II default values: comparison and offsets

FuelEU Maritime Annex II provides its own default WtW emission factor table, calibrated against JEC v5 and the EU’s Renewable Energy Directive (RED II) Annex V methodology. The values for petroleum-derived marine fuels are similar but not identical to MEPC.391(82).

For VLSFO, the FuelEU Annex II default is approximately 91.6 gCO2eq/MJ, broken into a WtT of 13.5 gCO2eq/MJ and a TtW of 78.1 gCO2eq/MJ (CO2 only, with CH4 and N2O captured separately as engine-related slip factors).

For MGO, the FuelEU Annex II default is approximately 94.4 gCO2eq/MJ, broken into a WtT of 14.4 gCO2eq/MJ and a TtW of 80.0 gCO2eq/MJ.

The systematic offset relative to MEPC.391(82) (FuelEU running roughly 1 gCO2eq/MJ higher) reflects three methodological differences:

1. Allocation method: FuelEU follows RED II Annex V which uses energy allocation between co-products at the refinery; MEPC.391(82) permits a wider menu of allocation methods including cut-off and system expansion, with energy allocation as a default.
2. Upstream methane scope: FuelEU includes a slightly higher upstream methane leakage assumption in line with the IEA Methane Tracker calibration; MEPC.391(82) tracks closer to JEC v5.
3. Refinery system boundary: FuelEU includes a small contribution from refinery hydrogen production where hydrogen is produced from steam methane reforming (SMR); MEPC.391(82) treats this similarly but with marginally different mass-balance assumptions.

For operators in EU trade who are also subject to the IMO Net-Zero Framework, the practical consequence is that the FuelEU intensity figure for a given bunkering will be 1 to 2 gCO2eq/MJ above the GFI figure for the same fuel. Both numbers can co-exist in compliance reporting because they answer different questions: FuelEU compares against an EU-specific 2020 baseline of 91.16, while the IMO GFS compares against the MEPC.391(82) reference of 93.3. The reduction-trajectory schedules also differ.

LCV: VLSFO ~40.5 MJ/kg; MGO ~42.7 MJ/kg

The lower calorific value (LCV), also called net heating value, is the energy released by complete combustion when water in the products remains as vapour. It is the energy basis used throughout MEPC.391(82) and FuelEU because it reflects the energy actually available to the engine. Higher heating value (HHV) is occasionally cited in commercial bunkering but is not used in regulatory accounting.

For VLSFO, the typical LCV is 40.5 MJ/kg, with a working range from 39.8 to 41.0 MJ/kg depending on aromatic and asphaltene content. Higher aromaticity (deeper colour, higher density) generally indicates lower LCV; more paraffinic blends sit at the higher end. The MEPC.391(82) default value is 40.5 MJ/kg and the FuelEU Annex II value is 40.5 MJ/kg.

For MGO, the typical LCV is 42.7 MJ/kg, with a range from 42.4 to 43.0 MJ/kg. The higher LCV reflects the higher hydrogen-to-carbon ratio of distillate cuts compared to residue; more hydrogen per kilogram means more energy released per kilogram burned. The MEPC.391(82) and FuelEU Annex II defaults agree at 42.7 MJ/kg.

The LCV matters for two operational reasons:

1. Energy denominator scaling: A ship that burns 100 t of VLSFO delivers approximately 4,050 GJ of energy to its engines; the same 100 t of MGO delivers approximately 4,270 GJ. The 5.4 percent uplift from MGO means that, for the same propulsion work, the ship needs 5.1 percent fewer kilograms of MGO than VLSFO. This partially offsets MGO’s higher per-MJ emission factor in voyage-total accounting.
2. WtW intensity normalisation: All emission factors are expressed per MJ, so any like-for-like comparison between fuels must use LCV as the bridging conversion. A bunker delivery note expressed in metric tonnes is converted to MJ via LCV before being multiplied by the gCO2eq/MJ default to give the total CO2-equivalent contribution.

Operators using /calculators/fuel-wtw-vlsfo and /calculators/fuel-wtw-mgo input fuel mass and the calculator handles the LCV conversion internally; for blended bunkers, /calculators/fuel-wtw-blend accepts a mix specification and energy-weights the components.

Upstream methane leakage assumptions

Methane leakage from upstream oil and gas operations is a small but rising contributor to WtW intensity for petroleum-derived fuels. The IEA Methane Tracker and academic literature (Alvarez et al. 2018, Rutherford et al. 2021) put global average upstream methane intensity for oil production at approximately 0.5 to 2.0 percent of associated gas production, equivalent to 0.5 to 2.0 gCO2eq/MJ on the WtW intensity of the resulting refined products.

The MEPC.391(82) default WtW factor for petroleum-derived fuels embeds approximately 0.8 gCO2eq/MJ for upstream methane at GWP100 of 28, calibrated against the JEC v5 working assumption of an average global crude slate. FuelEU Annex II uses approximately 1.0 gCO2eq/MJ, slightly higher to reflect more recent satellite-based emissions inventories.

The methane assumption matters because:

1. Different crude origins have very different methane footprints. Norwegian, Saudi, and Abu Dhabi production with extensive vapour recovery and minimal flaring sits at the low end (0.2 to 0.5 percent leakage). Permian Basin US shale, Russian Yamal, and West African production with limited vapour recovery and routine flaring can run 1.5 to 4 percent leakage.
2. Certified actual values under MEPC.391(82) can differ materially from the default depending on the refiner’s crude slate. Operators sourcing certified low-methane crudes through refinery-of-record certification can claim WtW values 1 to 3 gCO2eq/MJ below the default.
3. Voluntary methane reporting under OGMP 2.0 (Oil and Gas Methane Partnership) is increasing the data quality available for these calculations; the next MEPC.391(82) revision is expected to tighten the methane assumptions.

For a representative VLSFO bunkering of 1,000 t with default values, the upstream methane component contributes approximately 32 tCO2eq out of a total WtW footprint of around 3,690 tCO2eq, or roughly 0.9 percent. The figure is small but not negligible against the overall compliance position.

Refinery allocation methodology (cut-off / system expansion / mass-based)

Allocating refinery emissions between co-produced fuels is the single largest methodological choice in WtW LCA for petroleum products. A typical complex refinery produces 15 to 25 product streams (LPG, naphtha, gasoline, jet, diesel, gas oil, residue, lubricants, asphalt, petcoke) from a single crude input, and the way the refinery’s CO2 footprint is divided between them changes the per-MJ intensity of each product significantly.

Three methods dominate the literature:

Cut-off (or zero-burden): Co-products are assigned the actual emissions associated with their direct conversion processing (e.g., distillate hydrotreating energy attributed to distillates only). Streams that emerge from a shared upstream process (atmospheric distillation) take a per-mass or per-energy share of the upstream emissions. This method is computationally simple but tends to undercount the emission burden of high-value products like jet and diesel and overcount residue.

System expansion (substitution): Co-products are credited at their substitution value: if MGO production also yields LPG as a side stream, the LPG is credited at the avoided emissions of replacing natural gas in a downstream use. System expansion gives the most economically defensible numbers but requires assumptions about what each co-product would substitute, which introduces large uncertainty.

Mass-based or energy-based allocation: All refinery emissions are divided across products in proportion to their mass or energy content. This is the approach RED II Annex V mandates for biofuels and that FuelEU Annex II applies to petroleum products. It is the simplest to apply at scale and gives consistent results across refineries.

MEPC.391(82) Annex 1 uses energy allocation as the default but permits cut-off and system expansion where supported by certified data. FuelEU Annex II uses energy allocation only for default values, with deviations only permitted when underpinned by a recognised LCA scheme.

The practical consequence for VLSFO and MGO is:

• Under energy allocation, VLSFO carries approximately 9.0 to 9.5 gCO2eq/MJ at the refinery gate and MGO approximately 10.5 to 11.0 gCO2eq/MJ. The 1.5 gCO2eq/MJ spread reflects MGO’s higher hydrogen demand and refinery processing intensity.
• Under mass allocation, VLSFO and MGO would carry similar refinery footprints of approximately 9.5 to 10.0 gCO2eq/MJ; residue takes a larger share than under energy allocation because it accounts for a larger mass fraction of refinery output.
• Under cut-off, VLSFO would carry less (approximately 7 to 8 gCO2eq/MJ) because it bypasses most deep-conversion processing.

For operators on default values, the allocation methodology choice is invisible because the published Annex tables are pre-calculated. For operators pursuing certified actual values, the certification scheme’s allocation choice is the most consequential parameter in the WtW result.

ECA vs non-ECA fuel switching

Emission Control Areas (ECAs) impose a 0.10% m/m sulphur cap (versus 0.50% global) and stricter NOx Tier III limits in defined regions: the Baltic Sea, the North Sea (including the English Channel), the North American ECA (US and Canada coastlines), the US Caribbean ECA (Puerto Rico and US Virgin Islands), and from 2025 the Mediterranean ECA. Ships entering an ECA must either burn ECA-compliant fuel (typically MGO at 0.10% S, or LSMGO blended into VLSFO) or operate scrubbers (where permitted) on VLSFO to bring stack sulphur into compliance.

The ECA-vs-non-ECA fuel switching pattern matters for WtW accounting in three ways:

1. Fuel-mix shift: A ship operating substantially in ECA waters will burn a higher fraction of MGO than one trading globally. Because MGO has a higher per-MJ WtW intensity than VLSFO (93.3 vs 91.0 gCO2eq/MJ in MEPC.391(82) defaults), an ECA-heavy operating profile pushes the ship’s annual GFI position in the wrong direction. The increment is small per voyage but accumulates over the year.

2. Switchover ramp: ECA boundary crossings require a fuel switchover with a controlled fuel-tank flush and engine re-stabilisation. During the switchover, transient combustion conditions raise particulate and NOx emissions briefly, but the GHG impact is negligible. The switchover energy itself (heating, recirculation pumps) is small.

3. Bunker procurement and BDN documentation: Ships maintain separate VLSFO and MGO bunker streams. Each batch carries its own BDN and may have its own certified WtW value if the operator has invested in actual values. The MRV/THETIS-MRV reporting and IMO DCS reporting capture each fuel grade separately, so ECA-MGO and non-ECA-VLSFO consumption is visible at the regulator level.

For voyage planners, the trade-off between deep-sea VLSFO (lower per-MJ intensity, but global sulphur cap compliance) and ECA-MGO (higher per-MJ intensity, but ECA sulphur compliance and no scrubber) is essentially fixed by route geography. Where scrubbers are available and the ECA permits open-loop operation, scrubber-equipped VLSFO operation is the lower-WtW pathway, but scrubber capex and operational overhead must be weighed against the small WtW saving.

Commercial bunkering and the BDN chain

Every bunker delivery is documented by a Bunker Delivery Note (BDN) under MARPOL Annex VI Regulation 18, which is the formal record of fuel quantity, quality, sulphur content, supplier, and delivery time. The BDN chain is the documentary backbone of WtW accounting because it ties each batch of fuel consumed on board to a specific supply with traceable origin.

The BDN includes:

• Delivery date and time
• Receiving ship name and IMO number
• Supplying barge or terminal name
• Product name (VLSFO, MGO, etc.) and ISO 8217 grade
• Density at 15 °C
• Sulphur content (m/m percent)
• Quantity in metric tonnes
• Supplier signature and ship’s chief engineer counter-signature
• Sample reference (the MARPOL representative sample is sealed and retained for at least 12 months)

Under the IMO Net-Zero Framework and FuelEU Maritime, the BDN is augmented (in practice though not always in the regulation text) with WtW emission factor information so that the on-board energy management system can compute the GFI and FuelEU intensity contributions from each bunkering. Where the operator has procured certified actual values, the supporting LCA certificate accompanies the BDN.

Common BDN-chain risks for WtW accounting:

• Mis-grading: A batch labelled as VLSFO that is actually a heavily-cuttered residue with non-standard properties; the WtW default may not apply cleanly. ISO 8217 sample testing protects against this.
• Methane-leakage origin uncertainty: BDNs do not currently carry crude-origin information, so the upstream methane assumption defaults to the global-average value unless the operator has direct certification.
• Blend-stock substitution: Some VLSFO supplies in 2025 to 2026 have included biofuel blend components (FAME, HVO) at small percentages. These shift the WtW intensity downward but only if the bio-fraction is documented and certified. Undocumented bio-blending gives no WtW credit.
• Sample retention: The MARPOL representative sample is the legal evidence of fuel quality at delivery. Where a dispute arises over actual sulphur or carbon content, the sample is the reference.

The bunker procurement process is therefore evolving from a pure quality-and-price exercise to a quality-price-WtW exercise, with operators actively shopping for certified low-WtW supply where price differentials justify the operational complexity.

Relationship between SOx compliance and GFI

Sulphur compliance under MARPOL Annex VI Regulation 14 and GHG intensity under MEPC.391(82) and FuelEU are orthogonal regulatory dimensions. A fuel can be fully sulphur-compliant and still carry a high WtW intensity; a low-sulphur fuel does not automatically mean low GHG intensity.

The relationship is operationally entangled because both regulations apply to the same fuel batches, the same bunker streams, and the same combustion equipment. Three points of intersection matter:

1. Sulphur compliance does not lower GFI: Switching from HFO at 3.5% S to VLSFO at 0.45% S reduced sulphur emissions by approximately 90 percent in 2020, but the WtW CO2-equivalent intensity changed only marginally because both fuels are residual marine fuels with similar carbon content. The IMO 2020 cap was a sulphur and PM regulation, not a GHG regulation; its contribution to GHG reduction was limited to the modest refinery-energy uplift required to hit the lower sulphur target.

2. Scrubber operation neutralises sulphur cost but adds small GHG cost: Open-loop scrubbers consume electrical power (ship auxiliary load) for pump operation, which adds approximately 1 to 2 gCO2eq/MJ to the ship’s effective TtW. Closed-loop scrubbers add slightly more. Where scrubber-equipped tonnage runs HFO at 3.5% S as the input fuel, the WtW intensity is similar to VLSFO operation (HFO and VLSFO have nearly identical default factors) but with a small scrubber-energy penalty.

3. ECA fuel switching shifts GFI marginally: As covered in the ECA section, the per-MJ intensity differential between VLSFO and MGO is approximately 2.3 gCO2eq/MJ; ECA operation increases the MGO share and pushes the annual GFI upward by approximately 0.5 to 1.5 gCO2eq/MJ for an ECA-heavy trading pattern.

The practical implication for fleet planners is that meeting Tier 1 GFI targets and the 2027 to 2050 reduction trajectory cannot be done through fuel-grade selection within the conventional residual/distillate envelope; the GFI delta between VLSFO and MGO is an order of magnitude smaller than the trajectory cuts after 2030. Compliance comes from alternative fuels (biofuels, e-fuels, methanol, ammonia), not from optimising the residual-vs-distillate mix.

Formula, assumptions, and limits

Formula

The well-to-wake (WtW) emission factor for a marine fuel is:

where each component is itself a sum over the contributing greenhouse gases weighted by GWP100:

with $C_f$ the carbon mass fraction of the fuel (dimensionless), 44/12 the molecular mass ratio of CO2 to elemental carbon, and $m_{\text{CH}_4}$ and $m_{\text{N}_2\text{O}}$ the engine-out emissions of CH4 and N2O per kilogram of fuel burned (g/g fuel). LCV is the lower calorific value in MJ/kg.

For the WtT side:

with each term carrying its own weighted GHG composition.

Derivation

The TtW CO2 term derives from a simple mass balance: 1 kg of fuel contains $C_f$ kg of carbon; complete combustion produces $C_f \cdot (44/12)$ kg of CO2; this CO2 mass is divided by the energy released ($\text{LCV}$ MJ/kg) to express as gCO2/MJ. For VLSFO with $C_f = 0.864$ and LCV 40.5 MJ/kg:

The factor of 1000 converts from kg/MJ to g/MJ.

The CH4 and N2O contributions are calculated per-engine and per-fuel from emission-factor measurements. For VLSFO and MGO, default values of $m_{\text{CH}_4} = 0.00005$ g/g fuel and $m_{\text{N}_2\text{O}} = 0.00018$ g/g fuel give:

Summing all TtW contributions and adding the WtT default produces the Annex 1 WtW factor.

Assumptions

The default values rest on a chain of assumptions:

1. Global-average crude slate: Refinery emissions and upstream methane reflect a weighted average of crude streams supplied to the international bunker market. Local variations are not captured.
2. Energy allocation at the refinery gate: Co-products are apportioned by energy content. This is conservative for distillates and slightly favourable for residue.
3. GWP100 weighting from IPCC AR5: CH4 at 28, N2O at 265. AR6 values (CH4 at 27.9, N2O at 273) are not yet in the regulatory text but may appear in future revisions.
4. Engine-out emissions at typical operating loads: Default factors assume slow-speed two-stroke or medium-speed four-stroke marine diesel engines at 50 to 85 percent MCR. Low-load and starting-up emissions are not separately resolved.
5. No scrubber energy penalty: Default values do not account for scrubber operation; operators using scrubbers should add 1 to 2 gCO2eq/MJ if pursuing actual values.
6. No biofuel blending: Default values assume neat petroleum fuel. Bio-blends require certified blend documentation.

Worked example

A bulk carrier consumes 1,200 t of VLSFO and 80 t of MGO over a 30-day voyage that includes a 4-day ECA segment.

Energy delivered:

Total CO2-equivalent (using MEPC.391(82) defaults):

VLSFO contribution: $1{,}200 \cdot 40.5 \cdot 91.0 \cdot 10^{-3} = 4{,}422.6$ t CO2eq. MGO contribution: $80 \cdot 42.7 \cdot 93.3 \cdot 10^{-3} = 318.7$ t CO2eq.

Total: 4,741.3 t CO2eq across 52,016 GJ, equivalent to 91.2 gCO2eq/MJ on a voyage-weighted basis. Operators can verify this with /calculators/fuel-wtw-blend and feed the figure into /calculators/gfi-attained for the full-year compliance picture.

Edge cases and limits

The default values are not appropriate for:

1. Bio-blended VLSFO or MGO: A 24% B24 blend of FAME with VLSFO has a materially lower WtW intensity than neat VLSFO; the default factor cannot be used. Certified blend documentation is required.
2. Synthetic VLSFO from e-pathways: Some refiners are exploring synthetic residual fuels from CO2-derived hydrocarbons. These are not VLSFO in the WtW sense and require their own certified factor.
3. Heavily oxidised or off-spec fuel: A bunker stock that has degraded in storage may have a different carbon fraction and LCV; the default factors no longer apply cleanly.
4. Scrubber-equipped operation on HFO: HFO at 3.5% S burned through a scrubber gives stack sulphur compliance similar to VLSFO but the WtW factor for HFO (approximately 91.0 gCO2eq/MJ) plus scrubber energy penalty must be used, not the VLSFO default.
5. Engines outside the typical envelope: Very large two-stroke engines optimised for slow-steaming may have CH4 slip and N2O emissions outside the default range; manufacturer test data should be used.

Regulatory basis

• MEPC.391(82): 2023 Guidelines on Lifecycle GHG Intensity of Marine Fuels; Annex 1 default emission factors; revision schedule tied to MEPC sessions.
• Regulation (EU) 2023/1805 Annex II: FuelEU Maritime default WtW emission factors; aligned with RED II Annex V methodology.
• MARPOL Annex VI: Sulphur cap (Regulation 14), BDN requirements (Regulation 18), engine NOx limits (Regulation 13); orthogonal to GHG intensity but operationally entangled.
• IPCC AR5: GWP100 values used in both regulatory frameworks (CH4 at 28, N2O at 265).

Common errors

1. Mixing HHV and LCV: Some commercial bunker quotes use HHV; regulatory accounting always uses LCV. The HHV-to-LCV conversion is approximately 6 percent lower for residue, 7 percent lower for distillate.
2. Forgetting the GWP100 weighting on CH4 and N2O: The 28 and 265 multipliers convert mass of CH4 and N2O to CO2-equivalent. Omitting them under-counts the TtW intensity by approximately 1 gCO2eq/MJ.
3. Assuming MGO has lower WtW than VLSFO: On a per-MJ basis MGO is higher, not lower, despite its higher LCV. The refinery allocation shifts more emissions to distillate per MJ produced.
4. Confusing MEPC.391(82) and FuelEU defaults: They differ by approximately 1 to 2 gCO2eq/MJ; using one in the other framework’s calculation under-states or over-states compliance.
5. Treating sulphur compliance as a GHG strategy: Lower sulphur fuels do not have meaningfully lower WtW intensity. The two regulatory dimensions address different pollutants.
6. Using fuel mass for energy denominator: The FuelEU and IMO GFS denominator is energy in MJ, not mass in tonnes. Energy is mass times LCV.

See also

• /wiki/imo-2020-sulphur-cap
• /wiki/marpol-annex-vi
• /wiki/marine-gfs-methodology
• /wiki/fueleu-intensity-formula-breakdown
• /wiki/imo-net-zero-framework
• /wiki/tier-1-required-gfi-standard
• /wiki/gfi-reduction-trajectory-2027-2050
• /calculators/fuel-wtw-vlsfo
• /calculators/fuel-wtw-mgo
• /calculators/fuel-wtw-blend
• /calculators/fuel-wtw-hfo
• /calculators/fueleu-ghg-intensity
• /calculators/gfi-attained

References

1. ISO 8217:2024, Petroleum products, Fuels (class F), Specifications of marine fuels.
2. IMO MEPC.391(82), 2023 Guidelines on Lifecycle GHG Intensity of Marine Fuels.
3. Regulation (EU) 2023/1805 (FuelEU Maritime), Annex II default WtW emission factors.
4. JEC (JRC-EUCAR-CONCAWE) Well-to-Wheels analysis v5, EU Joint Research Centre.
5. CONCAWE Report 17/22, Marine fuel facts and refinery production pathways.
6. Argonne National Laboratory GREET model, lifecycle analysis of petroleum fuels.
7. IEA, Global Methane Tracker.
8. IPCC AR5, Working Group I, GWP100 reference values.
9. CIMAC Working Group 7 (Fuels), guidance on BDN and ISO 8217 sampling.
10. IMO MEPC 83 outcomes (April 2025), Net-Zero Framework adoption text.

Related calculators

• e-Diesel / FT e-Fuel - Well-to-Wake
• LPG - Well-to-Wake
• LNG - Well-to-Wake by engine pathway
• Methanol - Well-to-Wake by pathway
• Hydrogen - Well-to-Wake by pathway
• HVO / Renewable Diesel - Well-to-Wake
• FAME Biodiesel (B100) - Well-to-Wake
• Bio-LNG - Well-to-Wake

Related formulas

• fuel wtw vlsfo
• fuel wtw mgo
• fuel wtw nuclear
• fuel wtw methanol
• fuel wtw lpg
• fuel wtw lng
• fuel wtw hydrogen
• fuel wtw hvo