LNG

Singapore is at the heart of an evolving regional power grid which is poised to lower the share of LNG-fuelled power generation. If all proposed interconnections get built, they could unlock up to 25 GW of renewable and energy storage capacity worth over $40 billion, Rystad Energy reckons.

Today, over 96% of Singapore’s electricity is generated by burning natural gas which needs to be imported as LNG. Yet, Rystad analysis finds that importing electricity through the regional grid is cost-effective for the city state and could help reduce CO2 emissions by 13 million tons per year.

Higher load factor helps reduce electricity cost

Though CCGT are flexible and reliable in terms of operation, comparing the levelized cost of electricity (LCOE) reveals that electricity imports via ASEAN interconnectors may offer a more cost-effective alternative to building new domestic CCGT capacity. Singapore’s Electricity Market Authority (EMA) current regulatory framework require projects to reach an annual load factor of at least 60% within five years of commercial operation. For project developers there is a strong economic incentive to exceed this target.

Raising the load factor target from 60% to 100% could lower the overall LCOE, as this helps spread transmission costs more equally. This impact is particularly significant in countries such as Malaysia (Sarawak), Cambodia and Vietnam, where long transmission distances amplify cost optimization benefits particularly for hydropower projects

Solar-plus-storage hybrid systems, with optimized direct current/alternating current (DC/AC) configurations and appropriately sized battery energy storage systems (BESS), can already achieve load factors above 90%. By integrating solar and BESS technologies with the necessary backups, these systems can reach the level of reliability required by Singapore’s EMA and could be comparable to other dispatchable energy sources.

“Hybrid systems could deliver lower LCOEs than many in the industry currently anticipate. Singapore, strategically positioned at the heart of this evolving energy system, stands to gain significantly,” said Rystad’s renewables analysts Nevi Cahya Winofa.

First Gen is divesting 60 percent of its Philippine gas business to Prime Infra in a deal worth 500 billion Pesos (US$890m), covering controlling interests in BW Batangas FSRU, the proposed 1.2 GW Santa Maria power plant as well as the Santa Rita, San Sorenzo and Avion power plants (1,597 MW combined).

Santa Maria, a 1,200 MW combined-cycle power plant, will be fuelled via an interim offshore LNG terminal which is also part of the divested assets. Tokyo Gas had been contracted to supply an LNG cargo to First Gen in July 2024 which had been unloaded at the BW Batangas floating storage and regas unit (FSRU).

First Gen confirmed at the time it closed a tender for a cargo by awarding a contract to Tokyo Gas. Similar contracts were signed earlier with Shell Eastern LNG, Trafigura, TotalEnergies Gas and Power Asia and CNOOC Gas and Power Trading. The regasified LNG is designated for the First Gen Clean Energy Complex, comprising the Santa Rita, Avion and San Gabriel power plants.

The 1 GW Santa Maria CCGT used to supply baseload and mid-merit power to the Luzon grid. The Sta. Maria CCGT was initially meant to enter operations by the end of this year or early 2025, but the timeline slipped and First Gen now decided to divest its gas power assets altogether.

Following the sale, Prime Infra will hold the lion’s share of 60% in the Batangas-based gas power plants, with First Gen retaining the remaining 40%. The same equity split will apply to the LNG terminal, while Tokyo Gas of Japan will continue to hold a 20% stake.

Prime Infra already owns Prime Energy, the operator of the vast but depleting Malampaya gas field, which used to be a critical source of fuel for Luzon’s power generation.

First Gen Chairman and CEO Federico Lopez haled the deal as a “major step in our mission to forge collaborative pathways toward a decarbonized and regenerative future.” The partnership is meant to provide First Gen with more financial leeway to pursue its renewable energy projects.

As the largest renewable energy producer of the Philippines, First Gen covers about 18% pf the country’s electricity supply. Both First Gen and the media company ABS-CBN belong to the Lopez group of companies.

Switzerland-based Mercuria Energy Trading has entered into a long-term LNG sales and purchase agreement (SPA) with Guangzhou Gas Group. Mercuria called the deal a "pragmatic commercial collaboration and sustainable supply chain development," but fell short of disclosing financial terms or volumes.

“This long-term agreement enhances Guangzhou Gas Group’s capacity to secure stable gas resources, optimize the local energy mix, and reduce carbon emissions — enabling high-quality regional economic development,” Mercuria said in a statement.

Though prices and volumes were not made public, Mercuria stressed this agreement enhances its role as a strategic LNG partner in China and across Asia-Pacific, consolidating the foundation of its global LNG portfolio.

SPA with Oman LNG

The latest SPA follows Mercuria’s earlier deal with Oman LNG in February, under which Oman LNG will supply the Swiss trading company with 800,000 metric tons of LNG annually over a 10-year period on a free-on-board (FOB) basis.

Earlier this month, Mercuria also sealed offtake agreement with Cowboy Clean Fuels, a Wyoming-based company specializing in renewable natural gas (RNG). The deal marks the first commercial sale of RNG produced using CCF’s proprietary biomass carbon removal and storage methodology at its Triangle Unit Project near Gillette, Wyoming.

Mercuria describes itself as one of the world’s largest independent energy and commodity groups. Over 50% of its new investments are dedicated to renewables and transitional energy.

Shortfalls in Australia’s East Coast gas markets force regulators to make tough choices. Price caps, while offering short-term consumer relief, risk to undermine project economics and deter investment in future supply.

“Recent exemptions have effectively set a floor price as market participants anchor prices to the cap, making the market less responsive to supply-demand signals,” said Daniel Toleman, Wood Mackenzie’s research director of global LNG.

Export diversion is another option to help boost domestic supply but risks damaging Australia’s reputation as a reliable LNG supplier. “Queensland LNG projects were approved without domestic obligations and rely on long-term contracts,” Toleman said, explaining: “Diverting exports would require major infrastructure upgrades, as southern markets face the brunt of the shortfall.”

Imports 'commercially challenging'

Importing LNG through floating storage and regasification units (FSRUs) is “technically feasible but commercially challenging,” analysts warn. Global demand for FSRUs has surged since the Russia-Ukraine conflict, making units scarce and costly. The government may need to underwrite the commercial risk of such infrastructure.

Moreover, importing LNG would expose Australia to volatile global prices. Domestic gas prices would align with international LNG costs plus regasification and transport charges — potentially far exceeding current netback pricing.

Analysts pledge investors to come forward. Unlocking new domestic gas supply is the most effective way to reduce emissions and lower energy prices in Australia, Wood Mackenzie argues. But this would require a shift in government policy and a willingness to make politically difficult decisions.

Plans for Germany’s green hydrogen economy face serious delays due to uncertain future pricing and lagging infrastructure build-out, e.g. conversion of LNG import terminals and gas-fuelled power plants. Investment is slowly forthcoming: of the government’s targeted 10 GW new electrolyser capacity by 2030, only 1.6 GW has been instated so far.

“The hydrogen market is not scaling at the speed needed,” said Kerstin Andreae, chair of the German Association of Energy and Water Industries (BDEW) when presenting a new report co-authored by the consultancy EY.

“Investors and developers need clear rules, support for infrastructure, and reliable pricing signals to move forward,” she stressed. In fact, green hydrogen, produced by electrolysis using renewable electricity, made up just 0.5% of total hydrogen output in Germany in 2023 – while the vast majority is still made from fossil fuels, primarily natural gas.

The ‘Energy Transition Progress Monitor 2025’ warns that slow progress on key hydrogen infrastructure and weak investment conditions are stalling the ramp-up of green hydrogen. The report, published on Monday, cites a “significant investment hurdle” caused by regulatory uncertainty, infrastructure gaps, and market risks.

Industrial demand declines

Fossil-based generation of both hydrogen and electricity is becoming a new phenomenon amid weakening industrial demand, particularly in key sectors such as refining, ammonia, methanol, and chlorine production. Despite these setbacks Germany is on track to meet its 2030 climate targets, though analysts stressed shortfalls remain in the transport and heating sectors.

The incoming federal government faces “tremendous pressure” to deliver results, BDEW underlined. Key policy priorities include speeding up permitting for renewable projects, aligning grid expansion with energy demand, and designing a new electricity market framework that rewards flexibility and low-carbon solutions.

Industry groups, meanwhile, want the government to reinvigorate hydrogen efforts. BDEW and more than a dozen other trade associations called for a “restart” in bilateral energy ties aimed at forming a European hydrogen alliance. The groups called for an overhaul of EU rules on green and low-carbon hydrogen, the rapid buildout of cross-border hydrogen infrastructure, and harmonized certification standards across the bloc.

A close partnership with France, they argued, could “inject decisive momentum” into Europe’s hydrogen strategy. Signatories to the joint statement included BDEW, the chemical industry association VCI, the automotive group VDA, the local utility association VKU, and the European hydrogen lobby Hydrogen Europe.

India’s LNG imports are bound to rise amid higher gas-burn in the summer season and Petronet aims to get the expansion of the 17.5 mtpa Dahaj terminal to 22.5 mtpa completed in the next three months, CEO A.K. Singh said. He indicated Petronet aims to maximise the utilisation of this terminal over the summer.

Electric power generators across India have already been asked by the government to operate underutilised gas-fuelled plant at a higher capacity between May 26 and June 30.

Rain and cooler temperatures have subdued gas demand over the past few weeks but electricity demand is forecast to rise starkly as the summer season approaches. "We expect LNG demand to rise similar to last year's levels. Demand for power is rising in last few days so we are expecting demand for LNG to rise in the third or fourth week of May and in June," the Petronet CEO said.

Dispatch of gas-fuelled power plants has been more expensive than those running on thermal coal, solar or wind energy which results in three-fifth of all gas power stations standing idle. These plants tend to be primarily used for gas peaking power.

Yet the narrowing spread between spot and longterm LNG prices is incentivising buyers like Petronet to step up purchasing, Sing said, indicating Indian offtakers prefer LNG prices at below $10 per million British thermal units. At this level gas-burn for power generation starts to become economic.

Near-fixed price LNG offtake

For long, Petronet used to purchase US LNG at a near-fixed price. In September 2019, it signed a $7.5 billion agreement with Tellurian to take a stake in Driftwood LNG and import 5 mtpa. For American LNG vendors, selling LNG directly to Indian customers is difficult given that utility customers are hesitant to lock in long-term offtake agreements due to a high risk of price volatility at wholesale power markets.

Prime Minister Narenda Modi is pushing to turn India into a gas-based economy, aiming to boost the use of gas from 6.2% to 15% by 2030. To achieve this goal, the PM has set out measures to double city gas networks to 400 districts, set up an independent gas transmission system operator and a trading exchange to allow for transparent operations of pipelines and price discovery.

“Increasing natural gas use will enable India to fuel its impressive economic growth to achieve Prime Minister Modi's goal of a $5 trillion economy," noted Tellurian president and CEO Meg Gentle.

Mauritania will launch a bidding process in two weeks’ time for a 550 MW gas-fuelled power plant linked to the Greater Tortue Ahmeyim (GTA) liquefied natural gas project. The new power project will be developed and financed through a public-private partnership (PPP).

South Korean utility GS Energy and the construction firm BS Hanyang have been awarded a 1.1 trillion won ($815 million) project finance loan to develop the Northeast Asia LNG hub terminal in Yeosu. Built at a total cost of 1.4 trillion won, the project involves three LNG storage tanks with the first two slated to start operations by the end of 2027, and the third by the end of 2028.

Operations at the Revithoussa LNG regasification and import terminal in Greece have resumed after a planned shutdown to upgrade the plant with a new high-pressure BOG compressor. According to Greece’s National Gas System Operator (DESFA), the upgrade will eliminate the need for wasteful gas flaring during normal operations.

CPC Corp, Taiwan’s state energy company, is seeking to import LNG cargoes for August and September after the country’s last nuclear power plant was shut down over the weekend. LNG procurement will be ramped up through a new regas terminal in the Guantang Industrial Area.