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Per-fuel well-to-wake intensity: HFO (Heavy Fuel Oil)

Heavy Fuel Oil (HFO) is the high-sulphur (>0.50% m/m) residual marine fuel that dominated bunkering before 2020. Defined by ISO 8217 as the RM-grade table (RMA, RMB, RMD, RME, RMG, RMK) at sulphur up to roughly 3.5% m/m, HFO is the heaviest fraction left after atmospheric and vacuum distillation cuts have been removed at the refinery. Its well-to-wake (WtW) intensity under MEPC.391(82) Annex 1 is approximately 91.0 gCO2eq/MJ, with FuelEU Maritime Annex II assigning a comparable 91.6 gCO2eq/MJ default. The 2020 IMO 0.50% sulphur cap under MARPOL Annex VI Regulation 14 effectively ended unrestricted HFO use, leaving only scrubber-equipped tonnage trading on the Reg 14.4 equivalence pathway. Inside ECAs (Baltic, North Sea, North American, US Caribbean, and Mediterranean from 2025), HFO requires either an EGCS or fuel switching. The Antarctic Special Area and Arctic regions prohibit HFO carriage and use under MEPC.339(77) and MARPOL Annex I Regulations 43 and 43A. HFO emissions are NOT excluded from EU ETS maritime scope; full EUA liability applies. Compared with VLSFO and MGO and LNG Otto/Diesel, HFO carries similar carbon intensity but distinctly different sulphur and air-quality consequences. Operators size WtW exposure with /calculators/fuel-wtw-hfo, compare scrubber spreads via /calculators/fuel-wtw-vlsfo, and combine bunkers using /calculators/fuel-wtw-blend before feeding results into /calculators/fueleu-ghg-intensity and /calculators/gfi-attained.

Contents

Background: HFO as the dominant marine fuel pre-2020

Heavy Fuel Oil (HFO), also called residual fuel oil, bunker fuel, or bunker C, is the highest-boiling, highest-density, highest-sulphur fraction the modern refinery yields from atmospheric and vacuum distillation. For roughly five decades after the closure of coal bunkering on deep-sea vessels, HFO was the default fuel for slow-speed two-stroke and medium-speed four-stroke marine diesel engines. By the late 2010s, approximately 70 percent of global marine bunker volume was HFO at sulphur levels of 2.0 to 3.5 percent m/m, with the balance distillate marine gas oil (MGO) for ECA service and emergency use.

The economic logic was straightforward. Deep-conversion refineries producing road and aviation fuels accumulated vacuum residue and atmospheric residue streams with limited high-value outlets. Marine engines, designed with massive injectors, heated fuel systems, and tolerance for high carbon residue and ash, could burn this residue at a price discount of USD 100 to 250 per tonne against distillate. The fuel was cheap, energy-dense (LCV near 40.5 MJ/kg, density near 0.99 t/m3), and globally available at every major bunker hub.

The story changed on 1 January 2020 when the IMO global sulphur cap dropped from 3.50% to 0.50% m/m under MARPOL Annex VI Regulation 14. Ships without an exhaust gas cleaning system (EGCS, also called a scrubber) had to switch to compliant low-sulphur fuel, almost always VLSFO at 0.50% m/m or MGO at 0.10% m/m for ECA segments. HFO at 3.5 percent sulphur stopped being a permitted fuel for the bulk of the merchant fleet overnight.

The remaining HFO market today (2026) is approximately 5 to 10 percent of global bunker volume, concentrated in scrubber-fitted ships (around 5,000 vessels worldwide as of 2025) operating on the Regulation 14.4 equivalence pathway.

ISO 8217 RM-grade taxonomy (RMA, RMB, RMD, RME, RMG, RMK)

ISO 8217:2024 specifies marine fuel quality through two tables: a residual marine table (RM grades) and a distillate marine table (DM grades). HFO falls entirely within the RM table, with the specific grade determined by viscosity at 50 degrees Celsius and density at 15 degrees Celsius.

The RM grade nomenclature combines a letter (A through K) indicating viscosity class and a number (10 through 700) indicating maximum kinematic viscosity in cSt at 50 degrees Celsius. RMA 10 (max 10 cSt, density up to 0.920 t/m3) is the lightest residual grade. RMB 30, RMD 80, and RME 180 (densities to 0.991 t/m3) cover intermediate viscosity classes used for short-sea, ferry, and coaster trades. RMG 180 and RMG 380 (max 180 and 380 cSt; density up to 0.991 t/m3) include the global benchmark HFO grade RMG 380, the dominant deep-sea reference through 2019. RMG 500, RMG 700, and the RMK series (RMK 380, RMK 500, RMK 700) carry density up to 1.010 t/m3 and heavier viscosity, used where refinery economics and engine tolerance allow.

Sulphur in the RM table is specified at the legal cap applicable to the trade. Pre-2020, RMG 380 routinely carried sulphur of 2.5 to 3.5 percent m/m; post-2020, RMG 380 is supplied either as VLSFO at 0.50% m/m sulphur (technically still RMG 380 by viscosity but with a sulphur cap re-flagged) or as HFO at high sulphur for scrubber-equipped ships. The same RMG 380 viscosity envelope hosts both, with bunker delivery notes (BDN) under MARPOL Annex VI Regulation 18 distinguishing them by sulphur content on the document.

Other RM-grade parameters that matter operationally include carbon residue (MCR) up to 18 mass percent, ash up to 0.150 mass percent (catalyst fines, vanadium, sodium, aluminium), asphaltenes up to 14 mass percent (driving stability and compatibility), water up to 0.5 percent v/v, catalyst fines up to 60 mg/kg, and pour point of 0 to 30 degrees Celsius (HFO requires heating to 40 to 50 degrees Celsius for storage and 130 to 150 degrees Celsius for injection).

Refinery production pathway: HFO as residual

HFO is literally the bottom of the barrel. Crude arrives at the refinery via pipeline or VLCC tanker, is desalted, and fed into the atmospheric distillation unit (CDU) at 350 to 360 degrees Celsius. Atmospheric distillation separates light and heavy naphtha, kerosene, light gas oil, heavy gas oil, and atmospheric residue. The atmospheric residue is routed to the vacuum distillation unit (VDU) where reduced pressure allows further separation without thermal cracking, producing VGO, HVGO, and vacuum residue.

HFO is produced primarily by blending vacuum residue and atmospheric residue with cutter stocks (light cycle oil, vacuum gas oil, FCC slurry) to bring viscosity into the target RM grade. The blend ratio depends on crude slate and refinery downstream conversion capacity. A simple hydroskimming refinery produces relatively large HFO volumes (20 to 35 percent of crude throughput) because there is no coker, FCC, or hydrocracker to upgrade residue. A deep-conversion refinery with delayed coker, residue FCC, hydrocracker, or solvent deasphalting unit produces less (5 to 12 percent). A coking refinery can convert nearly all vacuum residue into petroleum coke and lighter products.

HFO sulphur depends on crude slate sulphur. Sour crudes (Iranian Heavy, Arab Heavy, Maya, Mexican, some West African) yield residue at 3 to 5 percent sulphur; sweet crudes (Brent, WTI, Bonny Light, Saharan Blend) yield residue at 0.5 to 1.5 percent. The pre-2020 global HFO pool averaged near 2.7 percent sulphur, dominated by Middle Eastern and Latin American sour residues.

The WtT energy intensity of HFO production reflects the simple position of residue in the refinery: residue carries less of the refinery energy footprint per MJ produced than distillates because it is the product of separation, not conversion. The MEPC.391(82) refinery default for HFO is approximately 3.0 to 3.7 gCO2eq/MJ, below the 5.0 to 5.2 figure for MGO.

Carbon content, LCV, density, viscosity

The principal physical and chemical parameters of HFO are: carbon mass fraction Cf≈0.85C_f \approx 0.85 (typically 0.847 to 0.866); hydrogen mass fraction Hf≈0.105H_f \approx 0.105 (lower than distillates because of heavier aromatic and asphaltenic content); sulphur mass fraction 1.0 to 4.5 percent m/m; LCV ≈40.5\approx 40.5 MJ/kg (working range 39.8 to 41.0; MEPC.391(82) and FuelEU defaults agree at 40.5); density at 15 degrees C of 0.95 to 1.01 t/m3 (RMG 380 typically 0.985 to 0.995, RMK 700 up to 1.010); kinematic viscosity at 50 degrees C of 30 to 700 cSt; pour point 0 to 30 degrees C; CCR/MCR of 8 to 18 mass percent (drives coking); asphaltenes 2 to 14 mass percent; vanadium up to 600 mg/kg (corrosive at high temperature); and sodium 0 to 100 mg/kg (can form low-melting eutectics with vanadium attacking hot section components).

The high carbon mass fraction is the principal driver of HFO’s WtW intensity. With Cf=0.85C_f = 0.85 and LCV 40.5 MJ/kg, the fuel emits approximately:

TtW CO2=Cf⋅4412LCV=0.85⋅3.66740.5≈0.0770 kgCO2/MJ=77.0 gCO2/MJ \text{TtW CO}_2 = \frac{C_f \cdot \frac{44}{12}}{LCV} = \frac{0.85 \cdot 3.667}{40.5} \approx 0.0770 \text{ kgCO}_2/\text{MJ} = 77.0 \text{ gCO}_2/\text{MJ}

This is essentially the same per-MJ TtW CO2 as VLSFO (78 gCO2/MJ) and slightly above MGO (75 gCO2/MJ), with the small differences driven by the carbon-to-hydrogen ratio and LCV.

WtT component (extraction, transport, refining)

The well-to-tank (WtT) component covers crude extraction through refining to bunker delivery at the ship’s manifold. Upstream extraction runs 3 to 6 gCO2eq/MJ depending on crude origin; sour heavy crudes from oil sands or thermal recovery sit at the upper end (5 to 7), conventional Middle Eastern crudes near the global average of 4 (the MEPC.391(82) default). Crude transport runs 0.5 to 1.5 gCO2eq/MJ (default 0.8); VLCC voyages from Arabian Gulf to East Asia push the upper range. Refining runs 3.0 to 3.7 gCO2eq/MJ for HFO, below the 5.0 to 5.2 figure for MGO because residue carries less of the refinery’s conversion energy burden. The exact figure depends on allocation methodology between co-products: energy allocation (the default in both MEPC.391(82) and FuelEU Annex II) assigns HFO a share proportional to its energy content. Distribution and bunkering add 0.3 to 0.8 gCO2eq/MJ (default 0.5), covering terminal storage tank heating, bunker barge consumption, and final transfer.

Summing the phases gives a typical WtT for HFO of approximately 8.0 to 9.0 gCO2eq/MJ in the MEPC.391(82) default table, slightly below VLSFO (9.0) and clearly below MGO (10.5). The upstream methane component embedded in WtT is approximately 0.8 gCO2eq/MJ at GWP100 of 28. Crude origin matters: Norwegian, Saudi, and Abu Dhabi production with extensive vapour recovery sits at 0.2 to 0.5 percent leakage; Permian shale and West African crudes with routine flaring run 1.5 to 4 percent.

TtW combustion CO2, CH4, N2O

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

TtW CO2 is calculated from the carbon mass fraction and LCV:

TtW CO2=Cf⋅4412LCV⋅103 gCO2/MJ \text{TtW CO}_2 = \frac{C_f \cdot \frac{44}{12}}{LCV} \cdot 10^3 \text{ gCO}_2/\text{MJ}

For HFO with Cf≈0.85C_f \approx 0.85 and LCV 40.5 MJ/kg, the figure is approximately 77.0 gCO2/MJ (working range 76.5 to 78.5 depending on the specific blend).

TtW CH4 (methane slip) is essentially negligible. The fuel contains no methane, and combustion of liquid hydrocarbons in marine diesel engines does not produce significant unburned methane. MEPC.391(82) assigns a default of approximately 0.00005 g/g fuel, equivalent to less than 0.05 gCO2eq/MJ after GWP100 weighting at 28. The methane slip story differs dramatically for LNG-fuelled engines where Otto-cycle slip can dominate the TtW intensity. TtW N2O formation during high-temperature combustion runs 0.00015 to 0.00018 g/g fuel, equivalent to 0.9 to 1.2 gCO2eq/MJ at GWP100 of 265. The MEPC.391(82) default is approximately 1.0 gCO2eq/MJ.

Incomplete combustion products (CO, unburned hydrocarbons, particulates) carry minor GHG implications but significant air-quality consequences. HFO’s high asphaltene and ash content drives particulate emissions materially higher than distillate fuels, contributing to black carbon (BC) with substantial short-lived climate forcing impact in Arctic regions. BC is not currently in the regulatory CO2-equivalent accounting but was a primary driver of the Arctic and Antarctic HFO bans. Summing TtW gives a typical figure for HFO of approximately 78 to 79 gCO2eq/MJ, essentially identical to VLSFO and slightly above MGO (76 to 78).

MEPC.391(82) Annex 1 default WtW for HFO

The Annex 1 default WtW emission factor table in MEPC.391(82) provides fall-back values for operators who do not bring forward certified actual lifecycle data. For HFO (residual marine fuel, sulphur greater than 0.50% m/m), the typical default WtW intensity is 91.0 gCO2eq/MJ, decomposing as WtT 9.0 (extraction 4.0, transport 0.8, refining 3.7, distribution 0.5), TtW CO2 77.0, TtW CH4 0.05, TtW N2O 1.0, with upstream methane of approximately 0.8 gCO2eq/MJ embedded in WtT at GWP100 of 28.

The HFO default and the VLSFO default in MEPC.391(82) are numerically very close because the carbon content, LCV, and refining footprint of the two fuels differ only modestly. The principal regulatory distinction is sulphur, not carbon: swapping HFO for VLSFO at the same mass throughput changes WtW intensity by less than 1 gCO2eq/MJ. This is a critical analytical point for operators: fuel switching from HFO to VLSFO does not deliver meaningful GHG reduction. The decarbonisation gain comes from switching to a different fuel family (LNG, biofuel, methanol, ammonia, hydrogen), not from reducing sulphur within the same petroleum residue family.

The default values are intended to be conservative representations of a fleet-average pathway. Operators able to demonstrate lower actual values through certified LCA documentation under a recognised certification scheme can claim WtW values below the default; common pathways tie to specific crude slates (low-flaring Saudi crudes, Norwegian methane-controlled production, Brazilian pre-salt with closed-loop gas handling).

FuelEU Annex II treatment

FuelEU Maritime Annex II provides its own default WtW emission factor table calibrated against JEC v5 and the EU Renewable Energy Directive (RED II) Annex V methodology. For HFO, 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).

The systematic offset relative to MEPC.391(82) (FuelEU running 0.6 to 1.0 gCO2eq/MJ higher) reflects three methodological differences: FuelEU’s RED II energy allocation versus MEPC.391(82)’s wider menu; a slightly higher upstream methane leakage assumption in FuelEU; and FuelEU’s inclusion of refinery hydrogen production from SMR. For operators in EU trade also subject to the IMO Net-Zero Framework, the FuelEU intensity for an HFO bunkering runs 0.5 to 1.0 gCO2eq/MJ above the GFI figure for the same bunker; both numbers co-exist because FuelEU compares against the EU 2020 baseline of 91.16, while the IMO GFS compares against the MEPC.391(82) reference of 93.3.

The FuelEU baseline of 91.16 gCO2eq/MJ was itself fleet-weighted on 2020 fuel consumption. An HFO-on-scrubber bunkering at FuelEU’s 91.6 default sits essentially at the baseline, meaning HFO use offers no FuelEU benefit and no penalty in 2025 absolute terms. The trajectory reduction (2 percent in 2025, increasing year by year) means HFO continues to track baseline through the decade and accumulates compliance liability against an ever-tightening cap.

The detailed comparison between HFO, VLSFO, and MGO is covered in the VLSFO and MGO WtW page. Key points for HFO context: WtW intensity at 91.0 gCO2eq/MJ (MEPC.391(82)) is essentially identical to VLSFO; sulphur is the differentiator (HFO 1.0 to 4.5 percent; VLSFO 0.50 percent or below); LCV, density, and viscosity sit in the same RM-grade envelope; asphaltenes can run higher in HFO; stability is operationally more predictable for HFO because the blend chemistry is standardised, while VLSFO had documented compatibility incidents in early 2020; and price runs USD 80 to USD 200 per tonne below VLSFO, driving scrubber economics.

The orthogonality of sulphur and GHG intensity is the single most important policy point. The two regulatory dimensions address different pollutants with different physical mechanisms.

2020 IMO sulphur cap and the end of unrestricted HFO

On 1 January 2020, MARPOL Annex VI Regulation 14 reduced the global sulphur cap from 3.50% m/m to 0.50% m/m. Inside ECAs, the cap had been at 0.10% m/m since 2015. The cap applies to all marine fuels used by ships of 400 GT or above when not equipped with an approved EGCS.

For non-scrubber-equipped ships, the cap was binding: HFO at 2.7 percent (global average) had to be replaced. VLSFO at 0.50 percent m/m emerged as the workhorse replacement, displacing HFO from approximately 70 percent of global bunker volume to less than 10 percent within the first quarter of 2020. MGO at 0.10 percent took a larger share of ECA-bound trade.

The Regulation 14.4 equivalence mechanism allows ships to continue burning higher-sulphur fuel if they install an approved EGCS achieving equivalent stack emission compliance. Type-approved scrubbers under Resolution MEPC.184(59) can demonstrate exhaust SO2 levels equivalent to fuel at 0.50 percent m/m or lower. This is the legal basis for continued HFO use after 2020.

The transition created secondary effects: a short-lived VLSFO compatibility crisis in early 2020 (fuel system fouling, sediment formation, engine wear from incompatible blends); a collapse of the HFO retail market at hubs without scrubber-equipped traffic, leaving HFO availability concentrated at Singapore, Rotterdam, and Fujairah; and structural compression of refinery margins on residue, lifting coker and hydrocracker capacity utilisation. The cap did not change HFO chemistry, ISO 8217 RM specifications, or engine compatibility; it changed only the legal regime under which HFO could be burned.

Scrubber-equipped HFO economics 2020-2025

The economic case for installing an EGCS rests on the HFO-VLSFO price spread. If HFO trades sufficiently below VLSFO to recover scrubber capital cost and operating cost over the ship’s remaining life, the investment makes sense. Through 2020 to 2025, the spread averaged USD 80 to 200 per tonne, with peaks above USD 250 in tight refining markets and troughs near USD 60 when crude prices were low. The spread is governed by crude slate availability (sour heavy crudes increase HFO supply), coker and hydrocracker capacity (deeper residue conversion widens the spread), scrubber fleet penetration, and bunker hub liquidity (Singapore and Rotterdam command tighter spreads).

A typical capesize bulker consuming 25,000 tonnes per year saves USD 2.0 to 5.0 million annually at a USD 80 to 200 spread. Capital cost is USD 2.5 to 4.0 million for open-loop, USD 4.0 to 6.0 million for hybrid, and USD 5.0 to 8.0 million for closed-loop. Payback at the median USD 140 spread is approximately 1.5 to 3 years for open-loop, 2 to 4 years for hybrid, and 3 to 6 years for closed-loop. Long-haul deep-sea trade with high consumption (VLCC, capesize, ULCS containership) see the strongest economics; short-sea and coastal trade see weaker payback.

The energy penalty of running a scrubber is approximately 1 to 2 percent of main engine power. Closed-loop systems carry NaOH consumption at USD 2 to 8 per tonne of fuel. The payback math has shifted as spreads narrowed in some quarters (driven by refiner residue conversion) and as port-level open-loop discharge restrictions proliferated; 2025 retrofits face a more uncertain environment than those who installed in 2018 to 2020.

Open-loop scrubber wash-water discharge controversy

Open-loop scrubbers spray seawater into the exhaust gas stream. SO2 dissolves into the water as sulphite and sulphate; the resulting acidic, sulphate-laden, and PAH-contaminated wash water is discharged overboard. The water carries sulphate ions above ambient seawater, polycyclic aromatic hydrocarbons (PAHs) from incomplete combustion of HFO, heavy metals (vanadium, nickel, lead, mercury) from fuel ash and engine wear, particulate matter, and reduced pH from dissolved SO2 forming sulphurous and sulphuric acid.

The discharge volume is large: a 50,000 kW main engine requires hundreds of cubic metres of seawater per hour for SO2 absorption. The IMO MEPC.184(59) Guidelines set discharge water quality limits (pH, PAH, turbidity, nitrates) and require continuous monitoring, but the limits do not eliminate the chemical content; they bound the worst cases. The environmental concern is twofold: cumulative ocean acidification and sulphate loading in heavily transited waters (Singapore Strait, Suez Canal approaches, English Channel); and heavy metal and PAH accumulation in port sediments and shallow coastal waters where exchange with open ocean is slow.

By 2025, open-loop discharge is prohibited in the territorial waters or port limits of Singapore (since 1 January 2020), Suez Canal, Belgium, key Australian ports (Sydney Harbour, Port Botany), specific Norwegian fjords (Geirangerfjord), German inland waters and Baltic ports, several French ports, California and other US state-level prohibitions (Connecticut, Hawaii, Massachusetts), several Chinese ports, Hong Kong, and a growing list of cruise destinations in the Caribbean and Mediterranean. The list expands roughly every quarter as port states evaluate cumulative discharge data. The IMO has not adopted a global open-loop ban as of 2026, but MEPC sub-committee discussions on EGCS discharge water quality continue. Operators planning long-life retrofits on open-loop systems face the risk that further port-level restrictions or eventual IMO action could strand the investment.

Closed-loop and hybrid scrubber alternatives

Closed-loop scrubbers use a fresh-water and caustic soda (NaOH) solution as the absorption medium, recirculating the wash water in a closed system. Absorbed SO2 reacts with NaOH to form sodium sulphite/sulphate, filtered and stored as sludge for shore-side disposal. No discharge to sea is required while operating in closed-loop mode.

Closed-loop has clear advantages: no port-level discharge restrictions, lower environmental impact in sensitive waters, and compatibility with future regulatory tightening if IMO or port states ban open-loop discharge globally. The disadvantages are higher capital cost (USD 5.0 to 8.0 million versus 2.5 to 4.0 million for open-loop), higher operating cost (NaOH at USD 2 to 8 per tonne of fuel), sludge handling logistics at port reception facilities, and larger equipment footprint.

Hybrid scrubbers combine both modes in a single installation, allowing the ship to operate open-loop in unrestricted waters and switch to closed-loop in port or restricted areas. Hybrid systems are the majority choice for new retrofits in 2024 to 2026 because they hedge against both spread compression and discharge restriction risk. Capital cost is approximately USD 4.0 to 6.0 million; payback at a USD 140 spread is 2 to 4 years on a typical capesize bulker. The closed-loop energy penalty is approximately 0.5 percent above open-loop.

EGCS Resolution MEPC.184(59) type-approval

IMO Resolution MEPC.184(59) (adopted July 2009) is the foundational guidance document for exhaust gas cleaning systems (EGCS) under MARPOL Annex VI. It sets the type-approval framework under which a scrubber installation is recognised as Reg 14.4 equivalent to burning low-sulphur fuel.

The resolution provides two type-approval schemes. Scheme A (continuous SO2 emission monitoring) approves the system as a unit with ongoing compliance demonstrated by exhaust monitoring. Scheme B (parameter-based monitoring) approves on the basis of system parameters (water flow, exhaust flow, fuel sulphur, engine load) with rigorous initial certification and parameter logging; it is less common because operational simplicity favours Scheme A.

The resolution sets wash-water pH limits (minimum 6.5 at the ship side with a 4-metre mixing allowance), PAH limits (continuous monitoring at 50 µg/L equivalent phenanthrene), turbidity and nitrate limits, and continuous data logging of wash-water quality, exhaust SO2/CO2 ratio, and engine load with reporting to the flag state.

The resolution has been revised under MEPC.259(68) (2015) and MEPC.340(77) (2021) to clarify monitoring requirements, wash-water discharge calculations, and type-approval scope. EGCS type-approval is performed by classification societies (DNV, LR, ABS, BV, CCS, KR, NK, RINA) acting on behalf of flag administrations. EGC Record Books must be kept onboard and made available to port-state inspectors.

ECAs are coastal regions where MARPOL Annex VI applies tighter sulphur and/or NOx limits than the global cap. The current SECA regions are the Baltic Sea and North Sea (sulphur 0.10% m/m since 2015; NOx Tier III since 1 January 2021), the North American ECA and US Caribbean ECA (sulphur 0.10% m/m since 2014 to 2015; NOx Tier III for engines built from 2016), the Mediterranean SECA from 1 May 2025, the Norwegian Sea SECA (entry into force pending, expected 2026 to 2027), and the Canadian Arctic ECA in development.

For HFO operation in ECAs, the Reg 14.4 equivalence pathway via EGCS allows the ship to continue burning high-sulphur HFO while meeting ECA stack compliance. The EGCS must achieve 0.10 percent m/m equivalent SO2 emissions rather than the 0.50 percent global cap, requiring higher water flow rates, finer atomisation, and tighter monitoring. Operators must demonstrate via continuous monitoring data and the EGC Record Book that the system delivered ECA-equivalent performance throughout the ECA passage.

ECA NOx Tier III is independent of fuel and applies to engine-build certification, not fuel quality. HFO-on-scrubber operation in a Baltic NECA still requires Tier III NOx compliance, typically delivered via SCR or EGR. HFO compatibility with SCR is sensitive to sulphur (catalyst poisoning) and ash (catalyst fouling); some operators install ash filters to protect SCR catalysts.

The Antarctic Special Area and Polar Code framework prohibits HFO use and carriage in Antarctic waters under MARPOL Annex I Regulation 43, in force since August 2011. The prohibition covers:

  • Heavy-grade oils with density above 900 kg/m3 at 15 degrees Celsius.
  • Heavy oils with kinematic viscosity above 180 cSt at 50 degrees Celsius.
  • Bitumen, tar, and similar derivatives.

The Antarctic ban is absolute: no carriage as fuel, no carriage as cargo, no transhipment. Ships transiting Antarctic waters must use distillate fuels (MGO at minimum) and must demonstrate compliance through bunker delivery notes, fuel tank sounding logs, and survey records.

The Arctic region is covered under MARPOL Annex I Regulation 43A, adopted by Resolution MEPC.339(77) in November 2021 and entering into force on 1 July 2024. Regulation 43A prohibits the use and carriage of HFO as fuel by ships in Arctic waters from 1 July 2024, with waivers available to:

  • Ships engaged in search and rescue operations or oil spill preparedness.
  • Ships exclusively in domestic trade by certain Arctic states (Canada, Norway, Russia, USA, Denmark/Greenland).
  • Ships flagged by an Arctic state and operating in that state’s waters until 1 July 2029 (the transitional waiver).

The Arctic HFO ban is a primary climate driver: black carbon emissions from HFO combustion settle on Arctic snow and ice, reducing albedo and accelerating melt. The MEPC.339(77) ban is the strongest IMO action to date on a fuel-specific climate measure outside the Net-Zero Framework and reflects the disproportionate climate impact of HFO BC in the polar environment.

The ban does not cover Antarctic explicitly under MEPC.339(77); the Antarctic prohibition is the older Regulation 43 framework. Together, the two regulations form the polar HFO regime: no HFO in Antarctica from 2011, no HFO in Arctic from 2024 (with phased waivers to 2029).

EU ETS treatment of HFO emissions

The EU Emissions Trading System maritime extension covers ships of 5,000 GT and above for voyages to, from, and within EU/EEA ports from 1 January 2024. HFO emissions are NOT excluded from EU ETS scope; full EUA liability applies to CO2 emissions from HFO combustion at the same scope rules as VLSFO and MGO.

The EU ETS phase-in schedule:

  • 2024: 40 percent of CO2 emissions covered.
  • 2025: 70 percent.
  • 2026 and beyond: 100 percent.
  • 2026 onward: CH4 and N2O included alongside CO2.

For an HFO-on-scrubber ship trading EU/EEA, every tonne of HFO burned within EU scope generates approximately 3.114 tCO2 at Cf=0.85C_f = 0.85. At an EUA price of approximately EUR 80 per tonne (2025 average), the EUA cost is roughly EUR 250 per tonne of HFO burned within EU scope (plus the methane and N2O surcharge from 2026).

Critically, the scrubber installation does not reduce EU ETS liability. The scrubber addresses sulphur and is irrelevant to CO2 accounting. Operators evaluating HFO-on-scrubber economics for EU trade must add the EUA cost to the scrubber operating cost; the HFO-VLSFO spread must cover both the residual fuel discount and the EUA difference (which is small because the carbon content of HFO and VLSFO is essentially identical).

The practical implication is that the HFO-on-scrubber economic case is largely indifferent to the EU ETS because the marginal CO2 emission is similar to VLSFO. Where the scrubber wins is on the bunker price spread alone, not on EUA savings.

The FuelEU Maritime intensity penalty mechanism is more interesting. Both HFO and VLSFO bunkerings track close to the FuelEU baseline of 91.16 gCO2eq/MJ; the trajectory reduction means both fuels accumulate compliance pool deficit over time. Operators chasing FuelEU compliance must blend in low-intensity fuels (biofuel, e-fuel, shore power), and HFO offers no advantage over VLSFO in that calculation.

Commercial implications: scrubber payback, retrofit, ban risk

The commercial picture for HFO-on-scrubber operation in 2025 to 2030 is shaped by several factors. Scrubber payback runs 1.5 to 4 years on a typical deep-sea bulker, tanker, or containership at the historical USD 80 to 200 spread; new retrofits in 2025 to 2026 face spread compression risk if refiner residue conversion accelerates, with some forecasts putting the median spread at USD 60 to 100 by 2027 to 2028, extending payback to 3 to 6 years. Retrofit complexity requires drydock time of 3 to 6 weeks, structural modifications for the absorber tower, seawater intake and discharge piping, monitoring instrumentation, engine room reconfiguration, and reassessment of trim, GM, and freeboard.

Ban-list expansion risk is a fast-evolving regulatory area; each year more ports add restrictions, and hybrid retrofits hedge while pure open-loop installations face stranding risk. Antarctic and Arctic exclusion removes HFO from polar trade entirely. End-of-life uncertainty matters for older ships: at current spreads, the scrap value of an older bulker may exceed the discounted cash flow of three to five additional trading years on scrubber economics. The counterfactual of running VLSFO without a scrubber from 2020 onward avoids capital cost, retrofit complexity, ban-list risk, and polar exclusion, with the trade-off resting entirely on spread and remaining trading life. Neither scrubbers nor HFO offer a path to FuelEU or IMO Net-Zero Framework compliance; the HFO-on-scrubber operator must invest separately in low-carbon fuels, efficiency measures, or pooling to manage compliance liability.

2025 outlook on residual fuel demand

The structural outlook for residual marine fuel demand through the late 2020s and 2030s is declining, driven by several converging forces. Decarbonisation regulation under the IMO Net-Zero Framework GFS trajectory and FuelEU Maritime year-on-year tightening pushes operators toward biofuels, e-fuels, LNG, methanol, and ammonia; even HFO-on-scrubber accumulates compliance liability against a tightening cap. Refiner residue conversion continues to expand, with the IEA projecting global coker capacity additions of 1.5 to 2.5 million barrels per day through 2030, reducing residue availability and lifting HFO prices toward VLSFO. Newbuilding fuel choice in 2024 to 2026 orders increasingly favours dual-fuel (LNG, methanol, ammonia-ready) propulsion, leaving scrubber retrofits on existing tonnage as the principal HFO market support. Polar exclusions structurally remove HFO from Arctic and Antarctic growth corridors. Port-level discharge restrictions continue to erode the open-loop value proposition. Cruise sector exit is well advanced, with major operators (Carnival, MSC, Royal Caribbean, NCL) phasing out HFO in favour of LNG newbuilds.

The residual fuel pool will not disappear in the 2020s. As long as crude refining produces vacuum residue and the global fleet retains scrubber-equipped tonnage with remaining commercial life (2030 to 2040 horizon for the 2018 to 2020 retrofit cohort), HFO bunkering will continue at hubs serving deep-sea trade. Volume is expected to decline from approximately 25 to 35 million tonnes per year in 2024 toward 10 to 15 million tonnes per year by 2035, with further declines through 2040. Operators exiting HFO can transition to VLSFO (no scrubber required, GHG-equivalent), MGO (slightly higher per-MJ emissions but lower particulate and BC), LNG, methanol, ammonia, or hydrogen.

Formula, assumptions, and limits

Formula

The well-to-wake intensity of HFO is computed as:

EFWtW,HFO=EFWtT,HFO+EFTtW,CO2+EFTtW,CH4+N2O slip \text{EF}_{\text{WtW,HFO}} = \text{EF}_{\text{WtT,HFO}} + \text{EF}_{\text{TtW,CO}_2} + \text{EF}_{\text{TtW,CH}_4 + \text{N}_2\text{O slip}}

where:

  • EFWtT,HFO\text{EF}_{\text{WtT,HFO}} is the well-to-tank component summing extraction, transport, refining, and distribution emissions per MJ of fuel delivered.
  • EFTtW,CO2\text{EF}_{\text{TtW,CO}_2} is the direct CO2 emission per MJ from carbon combustion: Cf⋅(44/12)/LCV⋅103C_f \cdot (44/12) / LCV \cdot 10^3.
  • EFTtW,CH4+N2O slip\text{EF}_{\text{TtW,CH}_4 + \text{N}_2\text{O slip}} is the GWP100-weighted contribution of methane and nitrous oxide.

For HFO with default parameters:

Carbon content≈0.85 kgC/kgFuel; LCV≈40.5 MJ/kg; density≈0.99 t/m3 \text{Carbon content} \approx 0.85 \text{ kgC/kgFuel; LCV} \approx 40.5 \text{ MJ/kg; density} \approx 0.99 \text{ t/m}^3

The numerical breakdown gives:

EFWtW,HFO=9.0+77.0+1.05≈87.1 to 91.0 gCO2eq/MJ \text{EF}_{\text{WtW,HFO}} = 9.0 + 77.0 + 1.05 \approx 87.1 \text{ to } 91.0 \text{ gCO}_2\text{eq/MJ}

with 91.0 gCO2eq/MJ being the MEPC.391(82) Annex 1 conservative default and 91.6 gCO2eq/MJ the FuelEU Annex II equivalent.

Derivation

WtT extraction uses a global-weighted average crude slate emission factor (approximately 4.0 gCO2eq/MJ) reflecting drilling, primary recovery, secondary recovery, associated gas handling, and field-level methane leakage.

WtT transport captures the energy expended in pipeline and marine transport from oilfield to refinery. For an average crude routed VLCC from Arabian Gulf to East Asian refinery, the figure is approximately 0.8 gCO2eq/MJ.

WtT refining allocates a share of refinery energy to HFO based on energy content under MEPC.391(82) and FuelEU Annex II energy-allocation methodology. Residue carries less of the refinery energy burden per MJ produced than distillate because residue is the result of separation, not conversion.

WtT distribution captures terminal storage tank heating (HFO must be kept liquid above pour point), bunker barge fuel consumption, and final transfer to the receiving vessel. Approximately 0.5 gCO2eq/MJ.

TtW CO2 derives from the carbon mass fraction times the CO2/C molecular ratio, divided by LCV:

TtW CO2=Cf⋅4412LCV=0.85⋅3.66740.5≈0.0770 kgCO2/MJ=77.0 gCO2/MJ \text{TtW CO}_2 = \frac{C_f \cdot \frac{44}{12}}{LCV} = \frac{0.85 \cdot 3.667}{40.5} \approx 0.0770 \text{ kgCO}_2/\text{MJ} = 77.0 \text{ gCO}_2/\text{MJ}

TtW CH4 for HFO is essentially zero because the fuel contains no methane and combustion of liquid hydrocarbons in marine diesel engines does not produce significant unburned methane. Default 0.05 gCO2eq/MJ.

TtW N2O is approximately 1.0 gCO2eq/MJ at GWP100 of 265, reflecting high-temperature combustion product formation in slow-speed two-stroke and medium-speed four-stroke marine diesel engines.

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 (specific crude origins, specific refineries) are not captured in the default.
  2. Energy allocation at the refinery gate: Co-products are apportioned by energy content. Mass and system-expansion allocations would give modestly different figures.
  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 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 in the default: The MEPC.391(82) and FuelEU defaults do not account for the 1 to 2 percent main engine power consumed by scrubber operation. Operators using actual values should add this energy penalty to the WtW intensity.
  6. No biofuel blending: Default values assume neat petroleum residue. Bio-blended HFO requires certified blend documentation.
  7. No black carbon weighting: BC is not currently in the regulatory CO2-equivalent accounting, despite its substantial short-lived climate forcing impact, particularly in polar regions.
  8. Sulphur is orthogonal to GHG: Sulphur reduction (HFO to VLSFO) does not reduce the CO2 footprint; the WtW intensity is essentially identical.

Worked example

A capesize bulk carrier with a fitted hybrid scrubber consumes 28,000 t of HFO over a calendar year on a Far East to Brazil iron-ore trade, of which 4,500 t is consumed within EU/EEA scope (at Rotterdam call legs).

Energy delivered:

E=28,000⋅40.5=1,134,000 GJ E = 28{,}000 \cdot 40.5 = 1{,}134{,}000 \text{ GJ}

Total CO2-equivalent at MEPC.391(82) default:

MCO2eq=28,000⋅40.5⋅91.0⋅10−3=103,194 tCO2eq M_{\text{CO}_2\text{eq}} = 28{,}000 \cdot 40.5 \cdot 91.0 \cdot 10^{-3} = 103{,}194 \text{ tCO}_2\text{eq}

EU ETS scope at 70 percent (2025) coverage of the 4,500 t EU portion:

METS=4,500⋅40.5⋅77.0⋅10−3⋅0.70=9,822 tCO2 M_{\text{ETS}} = 4{,}500 \cdot 40.5 \cdot 77.0 \cdot 10^{-3} \cdot 0.70 = 9{,}822 \text{ tCO}_2

EUA cost at EUR 80 per tonne:

EUA cost=9,822⋅80=EUR 785,760 \text{EUA cost} = 9{,}822 \cdot 80 = \text{EUR } 785{,}760

Verify with /calculators/fuel-wtw-hfo for WtW totals, and feed into /calculators/fueleu-ghg-intensity and /calculators/gfi-attained for compliance. The scrubber spread saving at USD 140 per tonne on the full 28,000 t consumption is USD 3.92 million, comfortably exceeding the annual EUA cost.

Edge cases and limits

The default WtW values are not appropriate for:

  1. HFO from waste residue or bio-co-processing: Some refiners are exploring bio-residue blending. The default factor cannot be used; certified blend documentation is required.
  2. HFO from heavy oil or oil sands feedstock: The upstream extraction emissions for diluted bitumen or oil sands can run 5 to 15 gCO2eq/MJ above the default. Certified actual values are warranted for specific crude slates.
  3. HFO with very high asphaltene content (RMK 700): Combustion characteristics differ from standard RMG 380; LCV and CCR may push outside the default envelope. Manufacturer test data for the specific engine should be used.
  4. Scrubber-equipped operation with high reagent use (closed-loop): Adds 1 to 2 gCO2eq/MJ from caustic soda upstream supply chain emissions plus 1 to 2 gCO2eq/MJ from main engine scrubber pumping load.
  5. Polar operation prohibition: HFO use in Antarctic waters since 2011 and Arctic waters from July 2024 (with phased waivers to 2029) is regulated separately from WtW accounting. The fuel is simply not permitted; WtW intensity is moot.
  6. Engines outside the typical envelope: Very large two-stroke engines optimised for ultra-slow-steaming may have CH4 slip and N2O emissions outside the default range; manufacturer test data should be used.
  7. Older engines without electronic injection: Pre-2000 engines burning HFO can exceed default N2O emissions due to less precise combustion control. Flag-state and class survey records should inform actual-value calculations.

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 Regulation 14: Sulphur cap (3.50 percent global pre-2020, 0.50 percent global from 2020, 0.10 percent in ECAs since 2015); Reg 14.4 equivalence for EGCS-equipped ships.
  • MARPOL Annex VI Regulation 18: BDN requirements (sulphur, density, viscosity, carbon residue, ash records).
  • MARPOL Annex I Regulation 43: Antarctic HFO carriage and use prohibition since 2011.
  • MARPOL Annex I Regulation 43A (MEPC.339(77)): Arctic HFO use and carriage prohibition from 1 July 2024 with phased waivers to 2029.
  • IMO Resolution MEPC.184(59) (revised by MEPC.259(68) and MEPC.340(77)): EGCS type-approval guidelines, wash-water discharge criteria, monitoring requirements.
  • IPCC AR5: GWP100 values used in both regulatory frameworks (CH4 at 28, N2O at 265).
  • Directive 2003/87/EC (as amended): EU ETS maritime scope, full coverage of HFO CO2 emissions for ships above 5,000 GT in EU/EEA trade.

Common errors

  1. Treating sulphur compliance as a GHG strategy: Switching from HFO to VLSFO does not deliver meaningful CO2 reduction. The two regulatory dimensions address different pollutants.
  2. Forgetting scrubber energy penalty in actual-value calculations: A scrubber consumes 1 to 2 percent of main engine power; this should be added to WtW intensity if pursuing certified actual values.
  3. Confusing MEPC.391(82) and FuelEU defaults: They differ by 0.6 to 1.0 gCO2eq/MJ for HFO; using one in the other framework’s calculation under-states or over-states compliance.
  4. Assuming HFO-on-scrubber reduces EU ETS liability: It does not. The carbon content and LCV are essentially identical to VLSFO; the EUA liability is the same per energy unit.
  5. Using HFO defaults for Antarctic or Arctic operation: HFO is prohibited in those waters. The relevant fuel is MGO (or biofuel under specific waivers).
  6. Mixing HHV and LCV: HFO commercial quotes occasionally use HHV; regulatory accounting always uses LCV (40.5 MJ/kg). The HHV-to-LCV conversion is approximately 6 percent lower for residue.
  7. Forgetting upstream methane: The default WtW embeds approximately 0.8 gCO2eq/MJ of upstream methane at GWP100 of 28. Omitting it under-counts the WtT by about 1 percent.
  8. 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.
  9. Treating scrubber retrofit as a decarbonisation step: It is a sulphur compliance step. Decarbonisation requires a different fuel pathway (LNG, methanol, ammonia, biofuel, e-fuel).

See also

References

  1. ISO 8217:2024, Petroleum products, Fuels (class F), Specifications of marine fuels, residual marine RM grades.
  2. IMO MEPC.391(82), 2023 Guidelines on Lifecycle GHG Intensity of Marine Fuels, Annex 1 default emission factors.
  3. Regulation (EU) 2023/1805 (FuelEU Maritime), Annex II default WtW emission factors.
  4. IMO MARPOL Annex VI Regulation 14, sulphur cap and Reg 14.4 EGCS equivalence.
  5. IMO Resolution MEPC.184(59), 2009 Guidelines for Exhaust Gas Cleaning Systems (revised MEPC.259(68), MEPC.340(77)).
  6. IMO Resolution MEPC.339(77), Arctic HFO use and carriage prohibition under MARPOL Annex I Regulation 43A.
  7. MARPOL Annex I Regulation 43, Antarctic HFO carriage and use prohibition.
  8. JEC (JRC-EUCAR-CONCAWE) Well-to-Wheels analysis v5, EU Joint Research Centre.
  9. CONCAWE Report 17/22, Marine fuel facts and refinery production pathways.
  10. Argonne National Laboratory GREET model, lifecycle analysis of petroleum fuels.
  11. IEA, Global Methane Tracker, upstream oil and gas methane intensities.
  12. IPCC AR5, Working Group I, GWP100 reference values.
  13. Directive 2003/87/EC (as amended), EU Emissions Trading System maritime scope.
  14. Clean Shipping Coalition tracker of port and coastal-state open-loop scrubber wash-water discharge prohibitions.