What are floating LNG plants and how are they reshaping global gas supply

The start of LNG exports from Eni's offshore Congo vessel signals growing industry confidence in floating LNG, as costs fall and companies seek faster ways to develop remote gas fields

A floating liquefied natural gas (FLNG) plant operated by Italian energy major Eni has started supplying gas to Europe from offshore Congo, signalling a shift for a technology, which was once held back by high costs and operational uncertainty. The vessel, called Nguya, is anchored in shallow waters off the Republic of the Congo and liquefies gas extracted from offshore fields for export to European buyers, including Spain and Italy, the Financial Times reported.

 

The development reflects a broader shift in how gas reserves are being commercialised, particularly in regions where building traditional land-based LNG infrastructure is difficult, expensive or exposed to security risks.

 

 

What is the Nguya and how does it work? 

Nguya is a floating industrial facility designed to liquefy natural gas at sea. It is reportedly longer than the largest US aircraft carrier and features extensive processing equipment, including pipes, cooling systems, turbines and storage tanks. The vessel cools natural gas to minus 162 degrees Celsius, converting it into liquid form, which reduces the gas volume significantly, allowing it to be transported economically by tanker over long distances.

 

The vessel was constructed by China’s Wison and delivered in under three years. Storage tanks designed in Japan were built separately and integrated into the hull, which helped speed up construction, FT reported. The project also required converting an existing floating platform, Scarabeo 5, into a pre-treatment unit to separate gas from oil and other liquids before liquefaction.

 

Floating LNG facilities replicate functions traditionally performed at large land-based terminals in countries such as the US, Qatar and Australia.

 

Why is floating LNG gaining traction now? 

The floating LNG technology has failed to achieve widespread acceptance till now because its initial projects encountered both cost overruns and operational difficulties. The Australian Prelude floating LNG vessel, which Shell operated, generated doubts about the project's commercial viability because it incurred expenses close to $12 billion.

 

However, industry participants now say costs have declined significantly. Eni estimates floating LNG construction costs have fallen by up to 40 per cent in recent years, to below $1 billion per million tonnes of annual capacity. This implies a construction cost of less than $2.5 billion for a vessel like Nguya, although total project costs are higher due to associated infrastructure.

 

Shipyards are also moving towards more standardised designs, which has helped improve timelines and predictability.

 

According to a report by energy intelligence firm Rystad Energy, the FLNG terminals are gaining momentum on the global LNG market, with capacity expected to triple by 2030. The independent energy research firm also said that the global FLNG capacity is set to reach 42 million tonnes per annum (Mtpa) by 2030, further climbing to 55 Mtpa by 2035, which would be almost four times the figure of 14.1 Mtpa recorded in 2024.

 

How does floating LNG address security and infrastructure challenges? 

Floating LNG plants allow companies to process gas offshore, avoiding the need to build extensive land-based facilities, which reduces exposure to logistical challenges, regulatory delays and security risks in politically unstable regions.

 

And this advantage becomes particularly relevant in Africa, where offshore gas reserves are significant but onshore infrastructure development has faced disruptions for decades. For instance, an onshore LNG project in Mozambique led by TotalEnergies was delayed for five years after a terrorist attack in 2021. In contrast, offshore floating LNG facilities in the region have continued operating.

 

Therefore, since floating plants are physically separated from land-based conflict zones and can operate independently of onshore infrastructure.

 

Where else is floating LNG being deployed? 

Several floating LNG projects are now operating or planned globally. One example is the Gimi vessel, deployed offshore between Mauritania and Senegal under a long-term lease to BP. The vessel was converted from an existing tanker and is part of a model where specialised companies build and lease floating LNG units to producers.

 

Companies such as Golar are focusing on this approach, converting older ships into LNG processing units, FT reported. Their business model allows gas producers to avoid large upfront investment in permanent infrastructure.

 

Africa has become a major focus, due to its offshore reserves and infrastructure constraints. Other emerging regions include Latin America, particularly Argentina, Guyana and Suriname, as well as parts of the Asia-Pacific.

 

In Argentina, Eni is planning a larger floating LNG project offshore Vaca Muerta using multiple vessels. The project is expected to eventually produce 18 million tonnes of LNG annually, comparable with large land-based export terminals.

 

What are the limitations of floating LNG technology? 

The floating LNG plants face operational constraints because both technical and environmental factors restrict their ability to deploy in ocean waters. The limited physical dimensions of ships create operational constraints which determine how much equipment can be installed on board.

 

According to industry experts, FLNG facilities are usually powered by gas turbines rather than electric drives used in some modern onshore terminals, which can affect efficiency and emissions performance, especially in a time when global talks about emission control are gaining traction.

 

Gas composition also varies between offshore fields, which affects processing requirements and plant design.

 

Why does this matter for global gas supply? 

Despite the drawbacks, the Floating LNG technology presents an alternative way to develop offshore gas reserves without building permanent onshore infrastructure. It can also be deployed more quickly and relocated once reserves are depleted, allowing operators to use the same asset across multiple projects.