LNG as marine fuel

LNG as marine fuel refers to the use of liquefied natural gas - primarily methane (CH4), liquefied at −162°C to approximately one six-hundredth of its gaseous volume - as a propulsion and auxiliary energy source aboard ships. The fuel offers near-zero sulphur oxide emissions and meaningful tank-to-wake carbon dioxide reductions compared with conventional residual fuel oils, making it the most widely adopted alternative marine fuel in the current fleet. Its full greenhouse-gas benefit is sensitive, however, to unburned methane released during combustion (methane slip), which can erode or reverse the CO2 advantage on a CO2-equivalent basis over a 20-year warming horizon. The ShipCalculators.com calculator catalogue covers the full lifecycle from well-to-wake intensity to boil-off and bunkering logistics. By early 2024, approximately 350 LNG-fuelled ships were in service worldwide and a further 650 were on order, not counting the dedicated fleet of LNG carriers that has burned its own cargo boil-off as fuel since the mid-1960s. Regulatory pressure from the IMO Carbon Intensity Indicator, EEDI, EEXI, FuelEU Maritime, and the EU Emissions Trading System has accelerated ordering activity since 2018.

Contents

Background and history

Origins of LNG as a commodity

Natural gas was first carried in liquid form aboard the Methane Pioneer, a converted World War II Liberty ship fitted with aluminium cargo tanks insulated with balsa wood, which completed the world’s inaugural LNG cargo voyage from Lake Charles, Louisiana, to Canvey Island, United Kingdom in January 1959. The cargo comprised five aluminium prismatic tanks totalling approximately 5,000 m³. The voyage proved that LNG could be transported across an ocean without catastrophic boil-off or structural failure of the tanks, validating a technology that had been theorised since the early twentieth century. The technology to liquefy methane at atmospheric pressure by cooling it to −162°C had been demonstrated at industrial scale in Cleveland, Ohio, in the 1940s - the Cleveland LNG storage facility explosion of October 1944 killed 128 people and prompted decades of caution before the technology was reconsidered for maritime use.

The Methane Princess and Methane Progress, purpose-built LNG carriers each of approximately 27,000 m³ capacity, were delivered in 1964 and established the first commercial bilateral trade route between Arzew, Algeria, and Canvey Island. These vessels used self-supporting Conch aluminium prismatic tanks, a containment design later superseded by the Gaz Transport membrane system and the Kvaerner-Moss spherical tank, which came to define the LNG carrier fleet through the 1970s and 1980s. The vessel type is described in detail in the LNG carrier article.

Boil-off as propulsion fuel on LNG carriers

LNG carriers burned their own boil-off gas from the outset. Boil-off - natural vaporisation of LNG caused by heat ingress through tank insulation - was an operational inevitability arising from the thermodynamic impossibility of perfect insulation at cryogenic temperatures. Rather than flare or vent it, operators routed the vapour to steam-turbine boilers, producing propulsive power at a rate of roughly 0.1–0.15% of total cargo volume per day. This practice made LNG carriers the first gas-fuelled ships in regular commercial service, though the fuel supply was effectively a by-product of the cargo rather than a deliberate bunkering choice. Steam turbine propulsion was the dominant configuration until the late 1990s; slow steaming and the relative inefficiency of steam turbines relative to diesel engines then drove a shift toward diesel-electric and slow-speed diesel configurations using forced vaporisation or reliquefaction. Details of the evolution of onboard fuel gas systems are covered in the companion article on the LNG fuel system.

Early adoption for non-cargo vessels

The first purpose-built LNG-fuelled vessel not carrying LNG as cargo was the Norwegian car-passenger ferry Glutra, which entered service in January 2000 on the Ørsta-Volda crossing in western Norway. Glutra used a medium-speed dual-fuel engine and drew LNG from a shore tank built for the purpose by Gasnor, a Norwegian LNG supply company. The vessel demonstrated that LNG bunkering could be delivered at a small scale without major port infrastructure investment and without the safety incidents that had previously made regulators cautious. Norwegian authorities extended the concept through the 2000s via the NOx Fund, a voluntary industry agreement established under a Memorandum of Understanding between the Norwegian government and industry in 2008, which financed clean-combustion retrofits as a subsidised alternative to paying Norway’s national NOx tax. The NOx Fund was instrumental in driving adoption of LNG across the Norwegian coastal fleet: by 2010, approximately 20 LNG-fuelled vessels were operating on Norwegian domestic routes, all in the short-sea and ferry sector.

The Viking Grace, a Viking Line car-passenger ferry delivered in January 2013 for the Stockholm-Turku route, became the first large passenger ship to operate on LNG. At approximately 57,000 gross tonnes, it was an order of magnitude larger than any previous LNG-fuelled vessel other than LNG carriers. Its four-cylinder Wärtsilä 50DF dual-fuel engines demonstrated reliable operation at high propulsive loads in the challenging conditions of the Northern Baltic, and the vessel attracted considerable attention from cruise operators and ferry companies evaluating compliance routes for the MARPOL Annex VI Baltic Sea Emission Control Area, which imposes a 0.10% sulphur limit on fuel. The Viking Grace was later fitted with a rotor sail (Flettner rotor) in 2018, becoming a reference vessel for combined alternative fuel and wind-assist technology.

Mainstream adoption in deep-sea shipping

The transition from niche application to mainstream deep-sea fuel began with the ordering by CMA CGM in 2017 of nine 23,000 TEU ultra-large container ships powered by high-pressure diesel-cycle dual-fuel engines (MAN ES ME-GI). The vessels, named after French literary and cultural figures, were delivered from 2020 and became the largest dual-fuel ships in service. Their commissioning demonstrated that LNG bunkering could be arranged at scale in the ports of Rotterdam, Hamburg, Zeebrugge, and North American terminals, resolving what had previously been cited as an infrastructure chicken-and-egg problem. The ordering of this series triggered competitive responses: MSC ordered LNG-capable vessels; NYK, Mitsui OSK Lines, and K Line ordered LNG-fuelled pure car and truck carriers (PCTCs); and the cruise sector saw orders from Carnival Corporation and its brands for LNG-fuelled cruise ships including AIDAcosma, delivered in 2022 from Meyer Werft, and ships in the Carnival Celebration class.

The 2015 adoption of the IGF Code by IMO provided the regulatory certainty that shipowners had sought before committing capital to LNG-fuelled newbuildings. Prior to the IGF Code, LNG-fuelled vessels had been approved on a case-by-case basis under SOLAS Chapter II-1, requiring individual flag state approval and class review. The IGF Code harmonised requirements internationally and allowed classification societies to issue standard notations with predictable survey schedules.

DNV’s Alternative Fuels Insight portal, which tracks the global gas-fuelled fleet, recorded approximately 350 LNG-fuelled ships in operation and around 650 on order as of early 2024 (excluding LNG carriers burning boil-off). The on-order figure represents a committed pipeline roughly twice the existing operating fleet, indicating the technology is still in a period of rapid deployment rather than operational maturity. By ship type, container ships and cruise vessels represent the largest share of on-order LNG-fuelled capacity by gross tonnage.

Physical and chemical properties

Composition

LNG is not a single compound but a cryogenic liquid mixture whose composition varies by supply source and by the degree of upstream gas processing applied at the liquefaction facility. Methane (CH4) is always the dominant component, typically 80–95% by mole fraction. Ethane (C2H6) contributes 5–15%. Propane (C3H8), normal and iso-butane, pentane, nitrogen (N2), and trace amounts of CO2 make up the remainder in varying proportions. Lean LNG from some US Gulf Coast liquefaction plants that process pipeline-quality gas contains more than 97% methane; LNG from some Nigerian and Algerian fields and from some gas formations in the Middle East carries higher ethane and propane fractions. The distinction matters for shipboard operations: the Wobbe index, methane number (resistance to knock in gas engines), and gross calorific value all depend on composition. High-ethane LNG may fall outside the certified Wobbe range of some dual-fuel engines, requiring blend-down or operational derating. Composition varies not only by source but also by the degree of weathering (preferential boil-off of lighter components) during storage and transit - LNG stored for extended periods in poorly insulated tanks or during long STS voyages becomes enriched in heavier hydrocarbons, raising its density and calorific value.

Density and cryogenic state

At atmospheric pressure and −162°C, LNG has a density of approximately 420–460 kg/m³, with the exact value depending on composition and precise temperature. The Klosek-McKinley method, standardised in various LNG custody transfer protocols and used internationally for commercial metering, calculates density from composition and temperature with an uncertainty of approximately 0.02%. At elevated pressure in Type C pressure vessels (typically 4–6 bar gauge), the saturation temperature rises above atmospheric-pressure boiling point and the stored LNG is compressed liquid; density increases to 600–620 kg/m³ depending on composition.

Type C tanks - cylindrical pressure vessels constructed to pressure vessel codes - are the dominant choice for LNG fuel tanks on non-carrier vessels because they tolerate partial filling at any level without sloshing loads on structural supports, simplify pressure management through their ability to hold pressure for extended port stays, and eliminate the requirement for a secondary barrier system that applies to membrane and Type B tanks. Their pressure-holding capability means that a vessel in port can experience moderate boil-off without requiring immediate gas consumption, up to the design pressure relief set point (typically 6–10 bar gauge). The principal disadvantage of Type C tanks is their relatively poor use of hull volume compared with membrane tanks - a cylindrical vessel in a ship’s hold leaves geometric void space around the cylinder that is dead volume. This trade-off is acceptable on smaller vessels but becomes more significant on large container ships where maximising cargo capacity is critical, which is why some very large LNG-fuelled container ships have explored membrane fuel tank designs analogous to LNG cargo tank designs.

Energy content

The lower heating value (LHV) of LNG is 49.5–50.0 MJ/kg, substantially higher than heavy fuel oil (HFO) at 40–42 MJ/kg. The higher mass-specific energy of methane reflects the high hydrogen-to-carbon ratio of the molecule (4:1 for CH4 versus approximately 1.8:1 for HFO). The net calorific value relevant to combustion emissions calculations is established by the fuel-lng-ncv formula, which accounts for composition and temperature.

Despite the mass-specific advantage, the volumetric energy density of LNG is substantially lower than HFO. LNG at atmospheric pressure contains approximately 23–25 GJ/m³ compared with roughly 40 GJ/m³ for HFO at ambient conditions. A vessel designed to carry a given quantity of HFO requires approximately 1.7 times the fuel tank volume to carry the LNG equivalent for the same range. This volumetric penalty is a persistent commercial challenge for deep-sea bulk carriers and tankers, where cargo capacity is at a premium and hull redesign is expensive. The fuel-lng-summary formula page compares these values in the context of voyage planning.

Boiling point and handling

LNG boils at −162°C at 1 bar absolute. Any heat ingress - through tank walls, pipework, or during transfer - causes vaporisation. The resulting gas must be managed: on cargo carriers it is burned as fuel or reliquefied; on fuel-tank vessels it is typically consumed by the propulsion system or flared through a gas combustion unit (GCU) when the main engine is not in gas mode. The boil-off rate (BOR) for well-insulated IMO Type B or Type C tanks is typically 0.1–0.15% of tank volume per day. The lng-bor formula quantifies boil-off for tank design assessment, and the lng-boil-off-rate-tank calculator allows voyage-level estimation. Managing boil-off during extended port stays requires either reliquefaction equipment or a GCU; the lng-gcu-capacity calculator sizes the GCU for a given vessel type.

Wobbe index

The Wobbe index - gross calorific value divided by the square root of the specific gravity relative to air - governs interchangeability of gas fuels in combustion equipment. For LNG vapour, the Wobbe index typically falls in the range 48–53 MJ/m³ (referring to the upper Wobbe index at standard conditions), depending on composition. Engines and gas trains are certified for a specific Wobbe range; LNG from compositions outside that range may require blending or system adjustments. The lng-wobbe formula page covers the calculation; the lng-gcv-iso6976 formula covers the gross calorific value step per ISO 6976.

Regulatory framework

IMO IGF Code

The International Code of Safety for Ships using Gases or Other Low-flashpoint Fuels (IGF Code), adopted by IMO Resolution MSC.391(95) in 2015 and entering into force on 1 January 2017, is the primary technical safety instrument governing LNG-fuelled vessels. The code establishes prescriptive requirements for fuel containment systems, piping layout, ventilation, gas detection, emergency shutdown, and crew competencies. It applies to all ships other than gas carriers (which are governed by the IGC Code) that use low-flashpoint fuels as propulsion energy. The imo-igf-code calculator assists with IGF Code compliance checks.

MARPOL Annex VI and Emission Control Areas

MARPOL Annex VI limits sulphur content in marine fuel oil globally (0.50% since 1 January 2020) and within Emission Control Areas (ECAs) to 0.10%. LNG as a fuel contains no sulphur; its sulphur oxide (SOx) emissions are effectively zero without any exhaust treatment. This makes LNG intrinsically compliant in all current ECAs - the Baltic Sea, North Sea, North American, and US Caribbean ECAs - without scrubbers or distillate fuel switching.

MARPOL Annex VI also regulates NOx through Tier I, II, and III limits. LNG combustion in conventional Otto-cycle dual-fuel (DF) engines produces approximately 20–30% lower NOx than HFO combustion in an equivalent diesel engine operating at Tier II, owing to the lower peak flame temperature of lean premixed combustion. Tier III compliance - required in the North American and US Caribbean ECAs for vessels ordered from 1 January 2016 - imposes an 80% NOx reduction relative to Tier I, which is a more demanding target than lean-burn LNG alone achieves. Tier III is typically reached on LNG vessels through exhaust gas recirculation (EGR), water injection, or selective catalytic reduction (SCR); see the article on selective catalytic reduction.

Particulate matter (PM) and black carbon (BC) emissions from LNG combustion are substantially lower than from HFO combustion, with PM reductions commonly cited at greater than 95%. BC is of particular concern under the Polar Code because BC deposition on sea ice accelerates melting; several LNG-fuelled cruise ships operating in Arctic and Antarctic waters cite the BC reduction as a primary environmental benefit.

Carbon intensity regulation

LNG’s CO2 emission factor is determined by the carbon content of the fuel. The IMO uses a Cf value of 2.75 t-CO2/t-fuel for LNG (methane), compared with 3.114 for HFO and 3.206 for marine gas oil (MGO). This lower Cf directly reduces the attained CII score of an LNG-fuelled vessel compared with an HFO vessel of identical transport work. The cii-attained calculator applies the appropriate Cf for the fuel type selected. Similarly, the EEDI framework accounts for the lower CO2 emission factor through the same Cf, with LNG-fuelled ships typically achieving an EEDI margin of 20–30% below the applicable reference line before any other design optimisation. The eedi-attained and eexi-attained calculators implement this calculation; the eexi-attained formula page documents the underlying method.

The co2-from-fuel calculator converts fuel mass consumed directly to CO2 mass using the appropriate Cf.

Emission profile

Tank-to-wake CO2

Tank-to-wake (TtW) CO2 emissions from LNG combustion are approximately 25% lower than HFO on a per-unit-energy basis, reflecting the lower carbon content of methane relative to residual fuel oil. A tonne of LNG produces approximately 2.75 t-CO2 on combustion; a tonne of HFO at LHV 40.5 MJ/kg produces approximately 3.11 t-CO2. On a per-MJ basis, LNG emits roughly 55 g-CO2/MJ compared with approximately 77 g-CO2/MJ for HFO - a reduction of about 28%.

The carbon content difference is fundamental chemistry: methane (CH4) has one carbon atom per four hydrogen atoms. Complete combustion yields CH4 + 2 O2 → CO2 + 2 H2O, producing one mole of CO2 per mole of methane (44 g-CO2 per 16 g-CH4, a mass ratio of 2.75). HFO is a complex mixture of polycyclic aromatic hydrocarbons, asphaltenes, and heavy straight-chain compounds; its average stoichiometry at LHV 40.5 MJ/kg corresponds to approximately 86% carbon by mass, yielding a Cf of 3.114 t-CO2/t-fuel. Marine gas oil (MGO), a lighter distillate fuel, has a Cf of 3.206 owing to slightly higher carbon content by mass fraction.

The TtW CO2 reduction translates directly into the attained Carbon Intensity Indicator (CII) for a vessel. Under IMO Resolution MEPC.337(76), a vessel’s attained CII is the ratio of CO2 emitted (fuel consumption multiplied by Cf) to a measure of transport work (distance sailed multiplied by a capacity measure). An LNG-fuelled vessel of identical size, speed, and trade to an HFO vessel produces approximately 28% less CO2 per unit transport work from combustion alone, giving it a CII rating approximately two letter-grade classes better on a direct fuel substitution basis, before any efficiency design differences are counted. The slow-steaming-and-cii article covers how vessel speed interacts with fuel type in determining CII.

Methane slip and CO2-equivalent emissions

The CO2 advantage of LNG is partially or fully offset by methane slip - the escape of unburned methane through the combustion process or via crankcase and valve leakage. Methane is a potent greenhouse gas: the IPCC Sixth Assessment Report (AR6, 2021) assigns it a global warming potential of 29.8 over a 100-year horizon (GWP100) and 82.5 over a 20-year horizon (GWP20). A slip rate of 2–4% in Otto-cycle dual-fuel engines, expressed as a fraction of fuel methane unburned, converts to a CO2-equivalent penalty that can neutralise the full TtW CO2 advantage on a GWP100 basis, or produce a net warming disbenefit on a GWP20 basis.

Published methane slip measurements vary widely. Large-bore four-stroke Otto-cycle DF engines (common on LNG-fuelled ferries and ro-pax vessels) typically produce 1–5 g-CH4/kWh in gas mode, with lower-end values from newer engine generations. Two-stroke Otto-cycle DF engines (used on deep-sea vessels) show slip in the range 1–3 g-CH4/kWh. Two-stroke diesel-cycle gas injection engines (Winterthur Gas & Diesel ME-GI, MAN ES ME-GI) achieve methane slip below 0.5 g/kWh because combustion occurs at higher pressure without the pre-mixed lean-burn combustion region where slip originates. Low-pressure diesel-cycle engines therefore retain the full TtW CO2 benefit as a net GHG benefit with considerably greater confidence.

Catalytic oxidation converters placed in the exhaust stream can reduce methane slip by 50–80% on Otto-cycle engines. Commercial products from companies including Dinex and Twintec have been installed on marine four-stroke engines; development programmes target zero-slip dual-fuel operation. The ch4-slip calculator quantifies methane slip in CO2-equivalent terms; the emis-methane-slip-co2eq calculator converts a measured g/kWh slip rate to a voyage-level CO2-equivalent impact. The marpol-methane-slip calculator computes compliance implications under proposed MARPOL methane regulation.

Well-to-wake CO2-equivalent

Well-to-wake (WtW) analysis extends the system boundary to include upstream extraction, liquefaction, shipping, and regasification of LNG. The upstream chain introduces additional methane emissions through fugitive losses from gas fields, compressors, and pipework. On a WtW GHG intensity basis using the IMO’s LCA Guidelines framework (MEPC.1/Circ.795), LNG from a well-managed supply chain shows a 15–20% reduction versus HFO when assessed on a GWP100 basis. The uncertainty is substantial because upstream methane leakage rates vary from under 0.5% in Norwegian and Qatari fields to 2–5% or above from some unconventional US shale sources. The fuel-wtw-lng calculator computes WtW GHG intensity; the fuel-wtw-lng formula page documents the calculation methodology.

FuelEU Maritime uses WtW CO2-equivalent intensity as its primary compliance metric, with default values for fossil LNG set in its delegated regulation. LNG’s default WtW GHG intensity under FuelEU Maritime is approximately 75–80 g-CO2eq/MJ, compared with approximately 93 g-CO2eq/MJ for HFO - a reduction of roughly 15–18% against the 2025 reference. This puts LNG ships broadly in compliance with the FuelEU 2025 target (2% reduction from the 2020 reference level) but short of the 6% target from 2030 onward without blend-in of bio-LNG or e-LNG. The fueleu-ghg-intensity calculator applies the FuelEU methodology; the fueleu-ghg-intensity formula page covers the GHG intensity calculation.

EU ETS implications

Under the EU Emissions Trading System for shipping, the obligation is set at tank-to-wake CO2. LNG-fuelled ships pay EU Allowances (EUAs) for their CO2 emissions at a rate consistent with the lower Cf of methane. From 2026, the EU ETS regulation extends to include methane and N2O from shipping, which will introduce an additional compliance cost reflecting the GWP-weighted methane slip on a per-voyage basis. This structural change in ETS scope removes the financial advantage that Otto-cycle DF engines hold over diesel-cycle engines on CO2 alone and creates a direct financial incentive to adopt low-slip combustion technology or catalytic methane oxidation systems.

Fleet adoption and commercial landscape

Committed operators

CMA CGM, the French container line and third-largest container shipping company by capacity, has committed most strongly to LNG, with over 30 LNG-fuelled vessels in service or on order as of 2024, including 23,000 TEU and 15,000 TEU container ships powered by MAN ES ME-GI diesel-cycle dual-fuel engines. The company has invested directly in LNG supply chains and bunkering infrastructure, establishing long-term LNG offtake agreements and stakes in regasification terminals to secure fuel supply for its fleet. CMA CGM’s total LNG investment, encompassing vessel premium costs, supply chain development, and bunkering vessel charters, represents one of the largest single-company commitments to an alternative marine fuel in shipping history.

MSC, the largest container line by TEU capacity, has ordered LNG dual-fuel tonnage alongside methanol vessels, demonstrating a multi-fuel strategy rather than single-fuel commitment. NYK Line and Mitsui OSK Lines of Japan operate LNG-fuelled car carriers (pure car and truck carriers, PCTCs) as part of their decarbonisation strategies aligned with Japan’s Nippon Kaiji Kyokai class society requirements. Wallenius Wilhelmsen, a Norwegian-Swedish PCTC operator, has committed to LNG as a bridging fuel on its main Europe-North America and Europe-Asia trades. Carnival Corporation and MSC Cruises have deployed LNG-fuelled cruise ships, with AIDAnova (delivered December 2018), the first cruise ship operating solely on LNG - though with an HFO backup capability - representing a significant milestone for the cruise sector.

Maersk, after early LNG evaluations, pivoted definitively to green methanol in 2021, cancelling an LNG newbuilding programme and ordering a series of methanol dual-fuel vessels beginning with Laura Maersk, delivered in 2023 and operated initially on conventional methanol with green methanol blends as availability permitted. Maersk’s decision reflected a view that methanol offered a clearer net-zero pathway, that green methanol supply could be contracted at scale through long-term agreements with producers, and that the methane slip issue on LNG created regulatory uncertainty incompatible with customer commitments on Scope 3 emissions. Maersk’s position is widely cited in the industry debate about LNG as a bridging fuel versus a stranded-asset risk for vessels with 20-year service lives extending to the 2040s.

Hapag-Lloyd, the German container line, has taken a different approach by investing heavily in ammonia dual-fuel engine development and ordering ammonia-ready vessels while maintaining an existing conventional HFO fleet, judging that the capital cost of LNG newbuildings was not justified given the WtW GHG uncertainty and the tightening FuelEU targets from 2030.

DNV’s Alternative Fuels Insight data as of early 2024 indicates that LNG remains the largest alternative fuel segment by number of vessels and by installed engine power, accounting for more than 70% of all alternative-fuel vessels in service, ahead of methanol, LPG, ammonia, and hydrogen. The dominance of LNG is partly a function of its 20-year head start over other alternative fuels in the non-carrier sector, but also reflects the breadth of the supply chain and the certainty of the physical infrastructure relative to other options.

Vessel types and engine configurations

LNG-fuelled vessels span virtually all major ship types. Large container ships predominantly use two-stroke dual-fuel engines, either Otto-cycle (Winterthur Gas & Diesel X-DF or MAN ES ME-GI series for diesel cycle). Ferries and ro-pax vessels use medium-speed four-stroke DF engines (Wärtsilä, MAN, Bergen, Rolls-Royce). Cruise ships use four-stroke DF engines in combined diesel-electric or mechanical drive configurations. Car carriers are split between two-stroke and four-stroke installations. Platform supply vessels and offshore support vessels were the dominant early adopters in the North Sea in the 2000s.

The choice between Otto-cycle and diesel-cycle engines turns on the methane slip trade-off discussed above. Otto-cycle engines have lower capital cost and established supply chains; diesel-cycle ME-GI engines are heavier, more expensive, require high-pressure gas supply at up to 300 bar, and demand more complex gas handling systems but produce negligible methane slip. For operators with aggressive WtW GHG targets, the ME-GI platform offers the most defensible LNG position; it is currently the dominant choice for CMA CGM’s large container ships.

The classification societies - DNV, Lloyd’s Register, Bureau Veritas, ABS, ClassNK - have each developed LNG-readiness and gas-ready notations that allow a vessel to be designed for LNG operation with only partial gas equipment installed at delivery, with the fuel gas system to be completed later. The class-dnv-gas-ready, class-abs-lng-bunker-ready, and class-lr-lng-ready calculators address readiness requirements for these notations.

Bunkering infrastructure

Bunkering modes

LNG bunkering is conducted by three methods: ship-to-ship (STS), truck-to-ship (TTS), and shore-to-ship (pipeline from jetty). STS using purpose-built LNG bunkering vessels (LBVs) is the dominant mode for large deep-sea vessels. TTS using cryogenic road tankers is practical for coastal and short-sea vessels with smaller fuel tanks; it is slow relative to fuel volume and is not viable for large container ships. Shore-to-ship jetty bunkering is available at a small number of dedicated LNG marine fuel terminals.

ISO 20519:2017 - Ships and marine technology: Specification for bunkering of liquefied natural gas fuelled vessels - governs the STS bunkering interface, including hose and coupling specifications, pressure ratings, overfill prevention, emergency release couplings (ERC), and safety zones. SIGTTO (Society of International Gas Tanker and Terminal Operators) publishes complementary operational guidance for LNG bunkering and is a principal standards body for the LNG bunkering sector.

Major bunkering hubs

Rotterdam (Netherlands) is the largest LNG bunkering hub in Europe, served by multiple LBVs and handling a high proportion of STS operations for container ships calling at Maasvlakte. The Shell-chartered Cardissa (delivered 2017, 6,500 m³ capacity) was one of the first purpose-built LBVs globally and operates primarily from Rotterdam. The Coral Methane (2009, 15,600 m³), though originally designed for small-scale LNG distribution, conducted early pilot bunker transfers. Zeebrugge (Belgium) is a primary bunkering hub for CMA CGM vessels calling at the North Sea terminal and hosts the Q-LNG 4000 and associated CMA CGM-affiliated infrastructure. Hamburg (Germany) is a growing STS hub for the north European container trades, with multiple LBVs servicing Hapag-Lloyd-controlled and independent vessels. Barcelona and Marseille-Fos (Spain and France) serve the Mediterranean trade routes including the Middle East and Suez Canal corridors. Sines (Portugal) has developed as an Atlantic hub on the Europe-Americas corridor.

Outside Europe, Singapore hosts the FueLNG Bellina (8,000 m³, an STS LNG bunkering vessel operated by the FueLNG joint venture of Keppel and Shell), serving the rapidly growing LNG-fuelled fleet on the Asia-Europe and intra-Asia trades transiting the Strait of Malacca. Singapore’s Maritime and Port Authority introduced a mandatory STS bunkering licence and metering requirements for LNG in 2020, providing a regulatory framework for commercial bunkering operations. Yeosu, South Korea, with NYK-affiliated infrastructure, serves vessels on Northeast Asian trades including Japan-Korea ferry and short-sea routes. Busan, South Korea, has also invested in LNG bunkering infrastructure. Chinese ports including Shanghai, Ningbo, and Shenzhen have LNG bunkering available primarily for coastal trade vessels, governed by Chinese-language CGAS standards. Jacksonville, Florida, was an early North American STS hub for container operations on the US East Coast-Caribbean trade.

Transfer rates in STS LNG bunkering typically range from 500 to 1,000 m³/h for standard LBVs, constraining the refuelling time for large container ships with fuel tank capacities of 10,000–18,000 m³. An LNG-fuelled 23,000 TEU container ship with a typical LNG consumption of 150–200 t/day at design speed may require a full bunker call of 1,500–3,000 t-LNG (approximately 3,600–7,200 m³) depending on voyage length, requiring 4–8 hours of transfer at standard rates. The lng-sts-bunker-time calculator estimates the duration of a ship-to-ship LNG bunkering operation given transfer rate, tank volume, and pre-cooling requirements.

LNG route economics are assessed by the route-lng-gulf-asia calculator for US Gulf to Asia trades and the route-lng-gulf-nwe calculator for US Gulf to Northwest Europe.

Price and volatility

LNG pricing for marine fuel follows the broader LNG commodity market, which is indexed to a combination of Henry Hub (US), JKM (Japan-Korea Marker), and TTF (Netherlands) benchmarks depending on supply region and contract structure. The marine bunker price is typically quoted at the bunkering port with a premium over the relevant base commodity price reflecting the cost of liquefaction, transport, storage, and LBV operation. In historical terms from 2015 to 2021, LNG marine fuel prices were broadly equivalent to or slightly above MGO on an energy-equivalent basis, ranging from roughly US$200 to US$400 per tonne of HFO-equivalent. This range represented a premium over HFO of approximately 30–50% in most years, partially offset by the lower Cf (and therefore lower EU ETS cost) and lower OPEX from the absence of scrubber maintenance.

The European energy crisis of 2021–2022, triggered by reduced Russian pipeline gas supply to Europe and competition for LNG spot cargoes, drove TTF prices to historically unprecedented levels. Spot LNG reached the equivalent of approximately US$1,500/t HFO-equivalent at the TTF peak in August 2022. This event was a severe stress test for the LNG-as-marine-fuel concept: operators who had ordered LNG newbuildings on the basis of projected LNG price parity with HFO or MGO faced fuel costs that were three to five times higher than those on equivalent HFO vessels for a period of approximately 12–18 months. The event accelerated interest in hedging strategies and in long-term LNG supply contracts with price ceilings indexed to oil.

Price volatility is structurally higher for LNG than for residual fuel oil because LNG is a globally traded commodity with tight supply-demand balances. Major liquefaction projects - Sabine Pass, Corpus Christi, Qatar Expansion (North Field East and North Field South), Australia’s Gorgon and Wheatstone - operate on 20-year binding offtake agreements at fixed-formula prices. Spot LNG volumes trade on a thin margin between contracted supply and total global demand; power sector and industrial demand in Europe, Japan, South Korea, and China competes directly with shipping for the same LNG molecules. Operators using LNG as marine fuel either accept spot price risk, hedge through commodity derivatives on the ICE TTF futures market, or negotiate long-term dedicated marine bunker supply contracts. The lifecycle total cost of ownership of an LNG-fuelled vessel, as computed by the lifecycle-fuel-tco formula, is highly sensitive to the assumed LNG price trajectory and the assumed CO2 cost trajectory.

Bio-LNG and e-LNG

Bio-LNG (biomethane)

Bio-LNG is biomethane (CH4 produced from organic feedstocks via anaerobic digestion or thermochemical gasification) that has been purified, upgraded to natural gas specification, and liquefied to the same cryogenic state as fossil LNG. Feedstocks include municipal solid waste and landfill gas, anaerobic digestion of agricultural slurry, crop residues, sewage sludge, and source-separated food waste. Advanced bio-LNG from cellulosic biomass - wood chips, straw, miscanthus - uses thermochemical routes (gasification followed by methanation or biological methanogenesis). The chemistry of the fuel molecule is identical to fossil LNG regardless of origin; the same engines, tanks, bunkering vessels, and metering equipment are used without modification or any hardware change. This physical fungibility is the primary commercial advantage of bio-LNG over ammonia or hydrogen, which require substantial changes to onboard systems.

The GHG distinction arises entirely in the upstream supply chain. Bio-LNG from landfill gas or sewage sludge digestion achieves a WtW CO2-equivalent intensity that is close to zero or even negative on a GWP100 basis: the counterfactual scenario (methane venting or flaring from the landfill) assigns a credit that offsets the combustion CO2. Under FuelEU Maritime’s default values, bio-LNG from waste and residue feedstocks carries a substantially lower WtW GHG intensity than fossil LNG, potentially qualifying for intensity values of 10–30 g-CO2eq/MJ against the fossil LNG value of approximately 75–80 g-CO2eq/MJ. This enables operators to improve their FuelEU compliance balance significantly even with small blend fractions of bio-LNG. FuelEU penalties, pooling, and multipliers covers how bio-LNG blending can affect the pooling and penalty calculation. The fuel-wtw-bio-lng calculator computes WtW intensity for bio-LNG; the fuel-wtw-bio-lng formula page documents the input parameters including the ILUC (indirect land-use change) factor applicable to relevant feedstocks under FuelEU and RED III.

Supply of bio-LNG at marine bunkering scale is currently limited. European production capacity is dominated by small-scale biomethane upgrading facilities with individual output of typically 500–5,000 Nm³/h; aggregation to the bunkering volumes required by large container ships (several hundred tonnes per call) requires a logistics chain of compression, liquefaction, road transport, and STS transfer that does not yet exist at most commercial ports. The Dutch gas grid operator Gasunie has developed liquefaction infrastructure that accepts pipeline biomethane and produces bio-LNG for truck and marine bunkering; the Port of Rotterdam has established a bio-LNG bunkering service drawing on this. Broader supply growth is projected through the late 2020s as EU renewable gas mandates under the Renewable Energy Directive (RED III) require fuel suppliers to blend increasing fractions of biomethane into the gas network, generating bio-LNG as a by-product of the grid injection surplus.

E-LNG (electrofuel methane, Power-to-Methane)

E-LNG, also called synthetic methane, renewable methane, or e-methane, is produced via the Sabatier reaction: carbon dioxide (CO2) is combined with hydrogen (H2) produced by electrolysis of water using renewable electricity, yielding methane (CH4) and water vapour. The stoichiometry is CO2 + 4 H2 → CH4 + 2 H2O. When both the renewable electricity input and the captured CO2 are sourced in accordance with RFNBO criteria - renewable electricity from a certified additive renewable power source, CO2 captured from air or a biogenic source rather than from fossil combustion - the resulting e-methane qualifies as an RFNBO under the EU Renewable Energy Directive III. After liquefaction to −162°C, e-LNG is physically identical to fossil LNG and bio-LNG in all handling, combustion, and metering characteristics.

E-LNG production is currently negligible at global scale. The round-trip energy efficiency of the full Power-to-Methane pathway is approximately 55–65%: electrolysis of water using proton exchange membrane or alkaline electrolysers achieves approximately 70–80% efficiency; the Sabatier reactor adds approximately 75–80% efficiency; compression and liquefaction consume a further 15–20% of the methane energy content. This compares unfavourably with battery-electric or hydrogen fuel cell pathways that avoid the methane synthesis step, but the advantage of e-LNG over e-hydrogen is that the existing LNG infrastructure and engine fleet requires no modification. The levelised cost of e-LNG from pilot projects in 2023–2024, accounting for electrolyser capital, CO2 capture cost, and renewable electricity at EUR 50–80/MWh, is estimated in the range EUR 1,500–2,500/t, compared with fossil LNG spot prices of EUR 300–1,000/t in the same period. E-LNG is therefore not commercially competitive without direct subsidy or a very high carbon price.

Under FuelEU Maritime, e-LNG produced from verified RFNBO inputs qualifies for the RFNBO double counting multiplier (a factor of two applied to the energy contribution in the compliance balance calculation), which effectively halves the effective WtW GHG intensity against the FuelEU target. The fueleu-rfnbo-multiplier calculator applies this factor to the compliance balance.

The principal commercial argument for building LNG-fuelled vessels as a net-zero-compatible asset relies on the assumption that bio-LNG and e-LNG will be available at bunkering scale by the mid-2030s to replace fossil LNG in the same infrastructure. This argument parallels the bio-methanol and e-methanol pathway for methanol dual-fuel vessels and the ammonia production pathway for ammonia dual-fuel vessels. None of these drop-in renewable fuel pathways has achieved confirmed commercial-scale availability at marine bunkering prices competitive with fossil alternatives as of 2024.

Comparison with alternative fuels

LNG versus HFO with scrubber

An HFO-fuelled vessel fitted with an exhaust gas cleaning system (scrubber) achieves sulphur ECA compliance at lower capital cost than an LNG conversion if the vessel is already designed around conventional fuel. A retrofit open-loop scrubber on a large container ship typically costs US$3–8 million for hardware and installation, compared with an LNG capital premium (additional newbuilding cost for cryogenic tanks, gas handling system, and dual-fuel engine) of US$15–30 million for a comparable vessel. The scrubber route preserves HFO’s higher volumetric energy density and avoids the tank and piping complexity of cryogenic fuel handling. However, scrubber-equipped vessels continue to pay the full HFO CO2 emission factor under the EU ETS; their CII and EEXI scores are not improved by the scrubber; and they will face increasingly tight FuelEU GHG intensity targets through the 2030s that HFO cannot meet regardless of scrubber installation. Open-loop scrubber wash water discharge is prohibited by port regulations in Belgium, Germany, Singapore, China, and several other jurisdictions, limiting flexibility in port calls. As CII, EEXI, and FuelEU requirements tighten, the CO2 advantage of LNG over HFO becomes an increasingly large financial credit, whereas scrubber investment delivers no direct carbon compliance benefit and may become a stranded asset as HFO faces compliance constraints.

LNG versus methanol

Methanol as a marine fuel is a liquid at ambient temperature and atmospheric pressure (boiling point 64.7°C), requiring no cryogenic handling and simplifying tank and bunkering arrangements relative to LNG. A methanol dual-fuel vessel can be refuelled from conventional liquid-cargo port infrastructure adapted for methanol toxicity and flammability controls. Methanol’s LHV is approximately 19.9 MJ/kg - substantially lower than LNG at 49.5–50 MJ/kg - requiring approximately 2.5× the fuel volume for equivalent energy. On a tank-to-wake basis, fossil methanol has a Cf of 1.375 t-CO2/t-fuel (only 44.2% of the HFO Cf) but a lower LHV means the per-MJ CO2 is 69 g/MJ, compared with 55 g/MJ for LNG - so LNG is actually slightly better than fossil methanol on a tank-to-wake per-MJ basis. Only green methanol offers a deep decarbonisation pathway; green methanol supply is similarly constrained to bio-LNG and e-LNG. The principal advantage of methanol over LNG is the absence of methane slip as a GHG concern, simpler cryogenic-free handling, and the perception that its green supply pathway via biomass gasification or power-to-X synthesis is more mature at small scale than Power-to-Methane.

LNG versus ammonia

Ammonia as a marine fuel contains no carbon; its complete combustion products are nitrogen and water vapour, making it a potential net-zero marine fuel when produced from renewable hydrogen. However, ammonia is acutely toxic to humans at concentrations above 25 ppm (IDLH 300 ppm, LC50 of the order of 1,700 ppm), has a low flammability range (15–28% in air), a relatively low calorific value of approximately 18.6 MJ/kg LHV, and produces NOx and potentially N2O (GWP100 approximately 273) on combustion. Ammonia dual-fuel engines were at late-development or initial-service stage as of 2024, with MAN ES and Wärtsilä both having engine test programmes underway. The safety case for ammonia fuelled vessels requires extensive consideration under the IGF Code framework and existing class rules are under active development. LNG has a 20-year operational advantage over ammonia in regulatory maturity, crew competency frameworks, and supply infrastructure.

LNG versus biofuels

Biofuels in shipping encompass FAME biodiesel, hydrotreated vegetable oil (HVO), straight vegetable oil (SVO), and bio-blends with HFO or MGO. Drop-in biofuels - particularly HVO and B30 FAME blends - can be used in existing diesel engines with minimal or no hardware modification, which is a significant capital advantage for fleet operators who have already ordered or taken delivery of HFO or MGO-fuelled vessels. The WtW GHG reduction depends on feedstock: HVO from used cooking oil achieves approximately 80–90% WtW GHG reduction against the fossil reference; FAME from palm oil offers minimal benefit and is excluded from FuelEU’s eligible feedstock list under sustainability criteria. Biofuel supply at the volumes required for large vessel fleets is constrained by competition from road transport, aviation, and power generation sectors. LNG offers greater volume certainty at established bunkering ports than biofuels, but carries fossil supply chain GHG limitations that bio-LNG and e-LNG must eventually address.

Safety, codes, and classification

IGC Code

The International Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk (IGC Code) applies to LNG cargo carriers. It sets requirements for cargo containment, secondary barriers, insulation, pressure relief, gas detection, and crew safety. LNG carriers are not formally covered by the IGF Code because they are regulated under the IGC Code for their primary function as gas cargo carriers; the boil-off fuel system is treated as an extension of the cargo system.

The igc-methane-lng calculator addresses specific IGC Code calculations for methane (LNG) as cargo.

Gas secondary barrier

For IMO Type B tanks, the secondary barrier (partial secondary barrier) must be capable of containing any leakage for a specified period. Type C pressure vessel tanks, common in fuel applications, do not require a secondary barrier because the vessel design assumes complete liquid containment. The gas-secondary-barrier formula covers the design check for the partial secondary barrier.

Crew competency

STCW (the STCW Convention) was amended at the Manila Conference in 2010 to introduce Basic and Advanced training requirements for seafarers on gas-fuelled ships, reflected in the STCW Code Section A-V/3. These requirements address familiarisation with LNG properties, fuel system operation, emergency response to gas leaks, and bunkering supervision. Classification society surveys and flag state vetting under the ISM Code include verification that crew certificates cover gas fuel endorsements.

The ISPS Code introduces additional security considerations for LNG bunkering operations, given the flammability hazard of LNG vapour cloud and the security exclusion zones required during bunkering.

Classification readiness notations

A gas-ready notation allows a vessel ordered without the complete LNG fuel gas system to certify that the structural and safety provisions for later installation are incorporated at build stage. The three leading notations are DNV’s Gas Ready, ABS’s LNG Bunker Ready, and Lloyd’s Register’s LNG Ready. Each specifies structural reserves, penetrations, space allocation, and partial piping runs that must be completed at delivery, plus a schedule of remaining equipment to be installed before gas mode operation commences. The class-dnv-gas-ready, class-abs-lng-bunker-ready, and class-lr-lng-ready calculators assist with the associated documentation checks.

Operational considerations

Boil-off management

Boil-off management on an LNG-fuelled vessel requires continuous monitoring of fuel tank pressure and temperature, particularly during prolonged periods at anchor or in port when propulsion fuel demand is low. A fuel gas management system (FGMS) controls the automatic selection of vapour return, vapour consumption by auxiliary engines, or diversion to the GCU. If the GCU is inoperative and all engines are in diesel mode, rising tank pressure represents an operational constraint on port dwell time. The lng-cool-down calculator estimates the tank cool-down time and liquid nitrogen requirement before the first LNG filling operation. The lng-heel-return calculator models the minimum LNG heel required to maintain tank temperature during a ballast voyage to avoid re-cool-down at the next bunkering port.

Custody transfer and quantity measurement

LNG custody transfer - the formal measurement of LNG quantity transferred at a bunkering interface - uses the CTMS (Custody Transfer Measurement System) methodology. Mass is the preferred unit; it is computed from metered volume at known density using the Klosek-McKinley density equation or equivalent composition-based calculation. Volume flow is measured by Coriolis mass flow meters or by LNG flow meters calibrated to ISO 12213 standards. The convert2-m3-gas-to-kg-lng and convert2-m3-gas-to-mmbtu calculators support unit conversions relevant to custody transfer reconciliation.

LNG bunkering on tanker vessels

LNG-fuelled chemical tankers and product tankers require additional gas-free certification procedures before entering dry dock or cargo tank entry, because LNG vapour and cargo vapour hazards interact. The tanker-bunkering-lng calculator addresses bunkering procedure planning for LNG-fuelled tanker vessels; the tanker-gas-free-certificate formula covers gas-freeing procedures.

LNG compressor and reliquefaction

Larger LNG-fuelled vessels, particularly LNG carriers and some large container ships, install reliquefaction plant to return boil-off to the fuel tank rather than consuming or flaring it. This is economically advantageous when the LNG commodity price is high and the vessel is in slow steaming mode with low energy demand. The lng-compressor-power calculator estimates the power demand of an LNG compressor or reliquefaction unit.

Current developments

Methane regulation at IMO

MEPC 80 (2023) and subsequent intersessional working groups have considered binding methane emission limits for dual-fuel gas engines, building on the 2023 IMO GHG Strategy (Resolution MEPC.377(80)), which targets net-zero GHG emissions from shipping by or around 2050 and a 30% absolute reduction in GHG emissions by 2030 relative to 2008 levels. The GHG Strategy explicitly includes methane and N2O as part of the total GHG basket, not just CO2 - a significant change from the previous 2018 strategy that focused on CO2. Draft proposals circulating at MEPC include methane slip limits expressed in g/kWh for low-pressure Otto-cycle engines operating in gas mode, with enforcement through flag state annual verification reports or through the Ship Energy Efficiency Management Plan (SEEMP). If such limits are adopted at levels below the current performance of typical four-stroke dual-fuel engines (approximately 2–4 g/kWh), they would require catalytic methane oxidation on existing Otto-cycle DF engines or migration to diesel-cycle engines for future newbuildings.

The EU ETS extension to methane from 2026 provides a more immediate and financially quantifiable incentive for methane slip reduction. A vessel with a methane slip rate of 2 g/kWh and an engine running at full power for 5,000 hours per year on a 15 MW installation would emit approximately 150 t-CH4/year, which at GWP100 of 29.8 represents approximately 4,470 t-CO2eq. At an EUA price of EUR 60/t, this represents approximately EUR 268,000/year in additional ETS cost on the methane alone. For large container ships with installed power of 50–80 MW, the ETS cost of methane slip becomes a significant operating cost item, creating a material financial case for catalytic methane oxidation or engine type selection even before any direct methane emission regulation is adopted. The EU has separately proposed methane emission regulations for the upstream oil and gas sector under Regulation (EU) 2024/1789, which may indirectly reduce fugitive upstream emissions from LNG supply chains exported to Europe, improving the WtW GHG profile of EU-imported LNG from US and Qatari sources.

IMO DCS and EU MRV reporting

LNG-fuelled vessels are subject to the same fuel consumption reporting obligations as HFO vessels under the IMO Data Collection System (DCS) and the EU Monitoring, Reporting and Verification (MRV) Regulation. The key difference is that LNG consumption is reported in mass (tonnes) and the CO2 equivalent is calculated using the methane Cf of 2.75. Vessels operating on a mix of LNG and pilot fuel (typically MGO at approximately 1–5% of total energy for diesel-cycle engines) must report each fuel separately and apply the relevant Cf to each. From the 2026 monitoring year, the EU MRV Regulation, as amended to align with FuelEU Maritime, will also require reporting of methane and N2O emissions in addition to CO2 for ships above 5,000 GT calling at EU ports.

LNG as a bridge fuel: the debate

The classification of LNG as a bridging fuel versus a long-term decarbonisation solution is a live commercial and policy debate. Proponents argue that the 15–20 year operational lifespan of an LNG-fuelled newbuilding coincides with the period over which bio-LNG and e-LNG supply will scale; that the near-zero SOx and low NOx profile delivers immediate local air quality benefits; that the CII, EEDI, and EEXI compliance margin is a bankable regulatory asset through the 2025–2035 period; and that the IMO’s 2023 GHG Strategy explicitly does not prohibit LNG as a transition fuel, recognising the need for interim measures before zero-carbon fuels are at scale. Critics point to the methane slip problem on Otto-cycle engines, the capital cost premium of LNG versus scrubber-plus-HFO, the high price volatility demonstrated in the 2022 energy crisis, and the risk that tightening WtW GHG requirements under FuelEU after 2030 will render fossil LNG non-compliant earlier than operators anticipate, creating stranded-asset risk for vessels delivered in 2024–2026 with expected service lives to 2044–2046.

The academic literature - including lifecycle assessment studies from Brynolf et al. (2014), SINTEF’s methane slip measurements, and Transport & Environment’s analysis of LNG shipping - is divided on the net climate benefit of LNG over HFO for vessels with typical operational methane slip rates. The consensus position as of 2024 is that diesel-cycle ME-GI engines with low methane slip provide a genuine and defensible climate benefit; that Otto-cycle DF engines provide marginal or uncertain net benefit on a GWP100 basis; and that neither provides adequate climate benefit on a GWP20 basis unless methane slip is virtually eliminated through catalytic aftertreatment.

The ShipCalculators.com calculator catalogue provides tools across this decision space, from voyage-level fuel cost modelling to lifecycle GHG intensity and regulatory compliance checks, supporting operators in quantifying these trade-offs with their own vessel and route data.

References

IMO Resolution MSC.391(95): International Code of Safety for Ships using Gases or Other Low-flashpoint Fuels (IGF Code), adopted 11 June 2015, entering into force 1 January 2017.
IMO MEPC.1/Circ.795: Guidelines on the method of calculation of the attained Energy Efficiency Design Index (EEDI) for new ships, as amended.
IPCC Sixth Assessment Report (AR6), Working Group I, Chapter 7: The Earth’s Energy Budget, Climate Feedbacks and Climate Sensitivity, 2021. Table 7.SM.7 (GWP100 for CH4 = 29.8; GWP20 = 82.5).
ISO 20519:2017, Ships and marine technology: Specification for bunkering of liquefied natural gas fuelled vessels.
IMO Resolution MEPC.328(76): Revised GHG Strategy for shipping, as updated by MEPC.377(80) (2023 IMO GHG Strategy).
IMO LCA Guidelines: MEPC.1/Circ.795 and subsequent amendments establishing the well-to-wake framework for marine fuels.
DNV, Alternative Fuels Insight portal, fleet statistics as of Q1 2024. Available at: https://www.dnv.com/services/alternative-fuels-insight
Regulation (EU) 2023/1805 of the European Parliament and of the Council (FuelEU Maritime Regulation), Official Journal of the European Union, 22 September 2023.
Regulation (EU) 2023/957 amending Regulation (EU) 2015/757 (EU ETS extension to shipping), Official Journal of the European Union, 10 May 2023.
SIGTTO, LNG Bunkering: Ship-to-Ship Transfer, 2nd edition, 2019.
Society of International Gas Tanker and Terminal Operators (SIGTTO), LNG Bunkering Guidelines, 2020.
Klosek J., McKinley C.: Densities of Liquefied Natural Gas and of Low Molecular Weight Hydrocarbons, Proceedings of the LNG Conference, 1968.
ISO 6976:2016: Natural gas - Calculation of calorific values, density, relative density and Wobbe indices from composition.
Brynolf S., Magnusson M., Fridell E., Andersson K.: Comparative lifecycle assessment of marine fuels: liquefied natural gas and three other fossil fuels, Proceedings of the Institution of Mechanical Engineers Part M: Journal of Engineering for the Maritime Environment, 2014.
IMO IGC Code: International Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk (Resolution MSC.5(48)), as amended.

External links

IMO IGF Code text (MSC.391(95)) - full text of the IGF Code via IMO official website
DNV Alternative Fuels Insight - global LNG-fuelled fleet statistics and order book
SIGTTO LNG bunkering resources - operational guidance and industry standards for LNG bunkering
ISO 20519 bunkering standard - ship-to-ship LNG bunkering interface specification
FuelEU Maritime Regulation text (EUR-Lex) - full regulation text