LNG

Analysts have revised down Asian gas demand by 1.7 million tons after Chinese LNG imports fell 0.9 mt in a flatlining economy. The revision follows a 2.7 mt demand downgrade at the start of the US-China tariff war which impacts purchasing power and reduced LNG demand to 3.6 mt year-to-date.

Turkish President Recep Tayyip Erdoğan has announced the discovery of a significant natural gas reserve at a well in the Black Sea. Estimated to hold 75 billion cubic metres (bcm) of natural gas at an estimated value of over $30 billion, the new find will put a lid on Turkey’s LNG imports.

"With this discovery, we will meet the natural gas needs of homes in Turkey for 3.5 years," Erdogan at the EPC Summit in the Albanian capital Tirana on Saturday. The novel discovery, worth an estimated $30 billion, has been found at a depth of 3,500 metres in the Goktepe-3 well, he disclosed.

Daily gas production at Turkey’s flagship Sakarya field in the Black Sea nears 9.5 bcm and a timely start of production at Goktepe-3 would reduce the country’s need to import natural gas for years to come. The government has for long urged state-run Botas to reduce its energy import bill by limiting LNG imports and forge closer ties to international upstream companies with a view to develop more domestic oil and gas reserves.

In 2025, Turkey’s LNG imports are forecast to surpass 9 million tons, equivalent to some 12.4 bcm – down from the 14.27 bcm of LNG imported two years earlier. The fall in LNG imports reflects the country’s shift to regional suppliers and drive to increase domestic gas production.

Deliveries of pipeline gas from Turkmenistan will rise 1.3 bcm by the end of this year, based on a contract that state-run Botas signed with Turkmengaz in March. Botas is handling over 90% percent of Turkey’s total gas imports. No details on pricing terms were provided, though Turkey’s energy minister Alparslan Bayraktar indicated volumes imported from Turkmenistan could rise up to 2 bcm per year.

Part of Botas’ imported LNG, shipped under long-term contracts, has been re-exported – either on small-scale tankers or in the form or shipped via pipelines to neighbouring countries. In 2023, Turkey exported 896 million cubic metres of natural gas with 371 mcm supplied to Bulgaria, 217 mcm to Greece (pipeline), and 102 mcm to Romania – all via pipeline. Another 206 mcm was sold to Swiss trading houses in the form of LNG.

To reign in excess supplies, Turkey is trying to re-negotiating long-term LNG supply deals, e.g. the ongoing discussions with ExxonMobil for 2.5 mtpa or less over a decade. Similarly, Botas is in talks with Shell over flexible term LNG supply.

Delivery of 1.1 mtpa of LNG over 10 years was recently agreed with TotalEnergy. First shipments envisaged for 2027, though the actual offtake might be scaled down if more cost-competitive natural gas can be produced in Turkey by that time.

A maiden LNG cargo has arrived at the 125,000 cubic meter KARMOL LNGT Powership Africa, moored off the Senegalese capital Dakar since June 2021. Arrival of the first cargo – onboard a TotalEnergies-chartered tanker – helps the African nation to convert several power stations from oil to natural gas.

KARMOL, a joint venture between Karpowership and Mitsui OSK Lines, is for long active in Senegal: the Turkish company is already operating a 235 MW powership since August 2019, which covers around 15% of the country’s electricity needs.

Technically speaking, KARMOL’s technique of regasifying LNG onboard a specially designed FSRU for direct use in a Karpowership helps accelerate the roll-out of LNG-to-Power projects in countries with no domestic gas resources.

Going forward, the Turkish-Japanese joint venture wants to convert its entire fleet of Powerships to LNG. To that end, the JV already has another FSRU under construction which will be released shortly and is destined to be deployed offshore Mozambique.

Gokhan Kocak, KARMOL board member, said the company has a “bold ambition” to offer LNG to Power across the world and especially within Africa. “The usage of FSRUs mean we can unlock the benefits of clean and affordable electricity for millions of people, even where countries have no domestic gas production or infrastructure,” he explained.

CPC Corp, Taiwan’s state-owned energy company, is preparing to ramp up LNG procurement through a new regas terminal in the Guantang Industrial Area. By importing more natural gas, utilities comply with the government’s policy to exit nuclear power by the end of this year.

The Guantang terminal, situated in the north of the island, will give CPC an additional option for importing LNG apart from its Taichung LNG terminal which is also being expanded.

The Taiwanese government wants to replace nuclear power with natural gas and renewables. To that end, the ratio of electricity generated from natural gas is meant to rise to 50%, the ministry of economic affairs said, specifying the mid-2025 as the deadline for the completion of the country’s nuclear exit.

Taipower seeks to adhere to the government’s Nuclear Free Homeland Policy and state-owned CPC Corp consequentially increased LNG imports since early summer last year, and recently got approval to build a new regas terminal at Kaohsiung. Unit 1 of Taipower’s last fully functional nuclear power plant was shuttered on July 27 2024, and the utility currently prepares to decommission Unit 2 in late August or September 2025. This will complete Taiwan’s nuclear exit.

Repowering Talin plant to replace lost nuclear capacity

By that time, however, the country will need to import substantially more LNG as gas-fuelled power station will need to be dispatched for mid-merit or even partly as a baseload power source. Repowering the Talin coal-fired power units to cleaner-burning natural gas is under consideration. Not only would this boost demand for LNG, combusting gas instead of thermal coal would also produce around 95,000 tonnes less sulphur oxide, 50,000 tonnes less nitrogen oxide, and 6.26 million tonnes less carbon dioxide annually.

CPC confirmed it will supply regasified LNG to the repowered Talin power plant at Kaohsiung Port. But the company was quick to add it would also supply gas to power industries, homes, other end-users, and source gas for storage to meet seasonal demand swings.

Plans to increase Taiwan's natural gas reserves from the current 7-day storage level to 14, have already been announced by the country’s Ministry of Economics in October last year. Greater gas storage requirements further add to rising demand for imported LNG. All these factors make the state gas buyer CPC Corp keep a vigilant eye on offerings from long-term LNG deliveries as well as on the spot market.

Privately-held Bosowa Energy Group, an East Indonesian conglomerate, has teamed up with BK LNG Solutions to accelerate Indonesia’s clean energy transition. The two partners agreed to develop floating storage units (FSRUs) for importing LNG to fuel gas-fired power plants and distribute small-scale LNG via ISO tanks to remote and underserved regions.

The cooperation allows Bosowa Energy to combine its domestic operational capabilities with BK LNG’s international LNG expertise. A key element of the partnership will be the re-powering of diesel-fuelled plants on remote island to run on natural gas. The initiative will not only help cut emissions but also improve electricity access and grid stability in remote and often underserved regions.

Pilot projects underway in East Indonesia

To that end, Bosowa and BK LNG want to deploy modular LNG regas units and develop a localized system of micro grids. Pilot projects are scheduled to launch in Eastern Indonesia towards the end of 2025, with plans to expand operations nationwide in the coming years.

By joining forces, Bosowa and BKLS aim to accelerate project execution. Muhammad Akram, Chief Operating Officer (COO) of Bosowa Energy Group said the partnership “not only enables us to diversify our energy portfolio with scalable LNG solutions, but also directly supports our mission to reduce emission to enhance energy reliability in underserved regions.”

Henry Kim, President of Singapore-based BK LNG Solutions, highlighted the company’s commitment to support Indonesia’s clean energy transition: "As a specialist in flexible LNG solutions (…) we are confident in our ability to deliver reliable and efficient natural gas solutions tailored to Indonesia's unique needs, which we believe are essential for a resilient energy transition,” he said.

Rival FSRU onstream in West Java

The Japanese shipping major Mitsui O.S.K Lines (MOL) has already put an FSRU into commercial operation in early April. The floating LNG import units helps provide fuel to a power plant in West Java. The project is one of Asia’s first integrated gas-to-power project that involves an FSRU.

Development of the Jawa 1 gas-fired plant and project development was handled by PT Jawa Satu Regas (JSR), a jointly established company with PT Pertamina, Marubeni, and Sojitz Corp. Debt financing was arranged via the Japan Bank for International Cooperation, Asia Development Bank (ADB), Mizuho Bank, MUFG Bank, Oversea Chinese Banking Corpn, Crédit Agricole and Investment Bank, and Société Générale Bank & Trust.

The American Petroleum Institute (API), whose members include Exxon Mobil, Chevron and Cheniere Energy, is calling on President Trump to exempt LNG tankers from a new rule. The novel regulation mandates producers to move 1% of their exports on US-built ships starting from April 2028, and that share would rise to 15% from April 2047 onwards.

The policy sent shockwaves through the industry when announced by the US Trade Representative on April 17. In a first response, API told the U.S. Energy Secretary Chris Wright and National Energy Dominance Council Chair Doug Burgum the ruling would risk to counteract progress of the Trump administration towards unleashing US LNG sales.

Individual US LNG vendors who do not comply with the rule risk to lose their export licenses, even though the percentages apply to the overall shipping industry and to vessels that LNG exporters do not own and control, API warns.

Quest to get rule abolished

The industry group has rushed to foster closer relation with USTR in a quest to get the rule amended, if not abolished. The aim is to ensure “feasible and durable policies that benefit consumers and advance American energy dominance," said Aaron Padilla, API's vice president of corporate policy.

Today, there are 792 LNG carriers in operation around the world, according to the AXS Marine shipping consultancy. Out of that total, the number of ships built in South Korea and Japan is 703 combined. Some 58 LNG carriers were built in China – and just five come from US shipyards and these 1970-era ships are laid up and currently not in operation, AXS Marine specified.

Unfeasible deadline

There is no way that US shipyards can churn out vessels fast enough to meet the deadline set by USTR and the Trump administration, market participants warn. "There are no such vessels in existence today, and building them would take decades, making compliance impossible for the industry," Charlie Riedl, executive director at the Center for LNG, told Reuters in a statement.

In fact, it would take five years to build one LNG carrier at either of the two American shipyards that have sufficiently long docks to build such a vessel. API CEO Mike Sommers hence urged the Trump administration “to exempt crude oil and refined product imports and exports - consistent with this Administration's approach to exempt these same products from baseline and reciprocal tariffs.”

Southeast Asia is expected to become a net LNG importer by 2032, with demand set to soar approximately 182% over the next decade. Wood Mackenzie forecasts the region’s gas demand will outpace both oil and coal, particularly in Malaysia, Thailand, the Philippines and Vietnam.

The Vietnamese Prime Minister Phạm Minh Chính has urged for an accelerated start-up of the country’s first LNG-fuelled power project. Out of 14 gas power projects in planning, only the Nhon Trach 3&4 plants are on track to be commissioned in the second and third quarter of this year.

Nhon Trach 3&4, developed by the EPC contractors SamSung C&T and Lilama on behalf of PV Power. Situated near Ho-Chi-Minh City in Dong Nai province, the plants have a design capacity of 1.500 MW (2x750MW) and an annual average power production of 9 billion kWh per year.

Urge to bring another 6 GW onstream

Speaking at an industry forum, PM Chính underlined the urgency of advancing the remaining projects, particularly the Block B–O Mon and Hiep Phuoc 1 combined cycle gas power plants, which together have a projected capacity of 6,634 MW. 

According to Vietnam’s Office of the National Steering Committee on Energy Projects, these two CCGTs are “the only other projects with a realistic chance of becoming operational before 2030.”

To meet that timeline, however, developers must finalize power purchase agreements (PPAs), gas sale agreements (GSAs), and secure debt financing by early 2026.

PetroVietnam in June signed multiple agreements with its partners to advance the Block B–O Mon project, yet efforts have had limited effect so far. The national oil major’s initiative involves offshore gas fields in blocks 48/95 and 52/97 along with a 400-kilometer pipeline, designated to deliver natural gas to the O Mon thermal power complex in southwest Vietnam.

Though Germany must phase out fossil gas by 2045 to become climate neutral, there is no clear roadmap for exiting natural gas in the power sector and the future role of LNG, the International Energy Agency (IEA) criticises. The German ‘LNG Acceleration Act,’ for once, stipulates an end of LNG imports by 2043 when terminals should be converted to hydrogen.

To meet that timeline, substantial investment in Germany’s traditional gas infrastructure would be required, analysts pointed out.

For repurposing LNG regas terminals to accommodate hydrogen, the key question is temperature. Methane liquefies at −160°C and hydrogen −253°C. The European Network of Transmission System Operators for Gas (ENTSOG) recommends terminal operators to carry out a risk assessment of LNG in order to analyse the impact on the process conditions, properties of mixtures and consequences.

As for storage, Germany has the largest gas storage capacity in the EU with around 40 gas storage facilities holding more than 24 bcm. Up to 1% hydrogen per volume can be blended into an average gas storage facility – while a pipeline that currently carries mainly natural gas can transport about three times as many cubic meters of hydrogen, an ENTSOG-G study finds.

Key gas pipelines in Germany include Nord Stream 1, which used to transport Russian gas through the Baltic Sea; the Yamal-Europe Pipeline, now primarily used to transport natural gas from Germany to Poland; the Trans Europa Naturgas Pipeline, connecting the German and Dutch gas grids; and the Europipe I and II pipelines, which import natural gas from Norway’s North Sea fields into Germany.

Clear timeframe needed for gas-to-H2 conversions

Looking at the power sector, there is currently no roadmap for exiting natural gas in the power sector. Unlike coal, no timeframe has been set out, though the target of 100% fossil-free generation by 2035 indicated the need for speedy gas-to-hydrogen conversions – or utilities face the risk of plant closures.

Uncertainty about tenders for hydrogen-ready power stations or a future capacity market is has made Germany’s largest utilities to withhold investment in new power stations, which, in turn, risks to push up wholesale power prices.

The IEA hence urges the incoming coalition government to clarify the timing of a future gas exit. Timeframes for mandated hydrogen conversions would provide industry with the certainty needed to invest in the required import infrastructure (for both natural gas and hydrogen) and industrial clusters.

Electrification in focus first, hydrogen and CCUS second

The industry in Germany is struggling to stay competitive in the face of rising fuel costs and high electricity prices. To mitigate the risk of deindustrialisation, IEA analysts recommend policymakers in Berlin should concentrate efforts on promoting energy efficiency and electrification” in the short run. The rising adoption of hydrogen and post-combustion carbon capture utilisation and storage (CCUS) are seen as e viable pathways in the longer term.

For now, Germany’s dependency on natural gas continues “without a clear end in sight,” analysts criticise the government’s failure to set out clear policies on how to enact the clean energy transition. The outgoing government’s Power Plant Strategy attempted to tender 12.5 GW of new natural gas-fired power plant capacity that could later run on hydrogen.

“In this way, the construction of new hydrogen-ready gas-fired capacity could avoid a fossil fuel lock-in that is not at odds with the electricity generation target, as long as the fuel switch takes place on time,” analysts acknowledged but called for more clarity around the viability of hydrogen-ready gas plants.

Gas peaking plants are believed to keep playing a vital role in grid balancing beyond 2035. But other flexibility options, notably industrial demand response, storage and interconnections, should be encouraged as these “may displace the need for additional generation capacity,” analysts argue. The IEA hence urges the German government to “move ahead with the future electricity market design proposals, including a capacity mechanism.”

Financial close on US LNG export projects could be at risk by a stable peace deal between Russian and Ukraine, analysts warn. Europe would subsequently rush to accommodate more Russian pipeline gas imports of up to 50 bcm per year, while the lifting of sanctions on Russian LNG would raise exports to 12 mtpa – undermining the economics of US LNG.

In the event of a ‘stable peace’, Wood Mackenzie expects European gas prices at the TTF trading hub to fall well below the US$8-9 per mmbtu that are forecast for 2028/29.

A collapse in TTF prices, in return, would lead to years of US LNG capacity underutilisation and delays to several expected FIDs on well-advanced LNG export projects.

US LNG projects may become collateral damage

As a knock effect, Henry Hub gas prices would plunge since the lower-than-expected LNG exports create a length in gas supply in the United States. This oversupply supports greater gas-burn for power generation and may well reduce wholesale electricity prices to the benefit of American households and industries.

But Wood Mac’s vice president of Gas and LNG research, Massimo Di-Odoardo warned that with an average of 25 mtpa of liquefaction capacity in the United States and Mexico at risk of underutilisation over the next five years, “US LNG would be the collateral damage,”

More shipments needed in event of no peace

On the other hand, a failure to reach an agreement would results in "stronger for longer" gas prices as even less Russian supply comes to market.

“A continuation of the war could see the EU double down on sanctions, pushing even harder to achieve its ambition of independence from Russian energy - banning LNG imports from the Yamal LNG project and the 15 bcm a year TurkStream pipeline,” Di-Odoardo noted.

This scenario strengthens the need for more LNG supply, with US and Qatar capitalising on more investment opportunities.

"The outcome of ongoing negotiations for a peace agreement between Russia and Ukraine remains highly uncertain,” he said, concluding: “All scenarios are possible, including potential combinations of them, however, recent development suggest a peace agreement where the US and EU take different approaches to lifting sanctions, appears more likely.”