LNG

Though India has not yet mandated the dispatch of gas peaking power stations, analysts see upside risk to LNG-burn following a government tender to purchase 1.8 Gigawatt of gas-fuelled generation between April and October. Torrent Power was awarded 1.35 GW, with Kashipur Gama and Kondapalli Lanco taking the rest of the tendered capacity.

Energy Aspects understands the three power producers will receive a fuel price linked to the CME west India LNG prices.

“This power tender alone translates to LNG demand of 0.12 million tons per month over the second quarter of 2025, assuming a 50% load factor and 50% thermal efficiency,” analysts explained, stressing:

“This demand will be price insensitive, as LNG is effectively subsidised by the government.”

Early heatwaves have propelled up electricity demand in India to record levels. The average load factor in March reached 211.3 GW, the highest level ever recorded and a 12.4 GW rise year-on-year. The amount of cooling degree days was 9% above the 10-year norm, but analysts anticipate Indian CCDs will be a staggering 19% above the 10-year average over the next two weeks.

Should this prolonged heatwave materialise, India’s power load jump to new record highs averaging 227 GW over the second quarter, up by 8 GW compared to Q2-23.

Though the LNG tenders are bound to increase gas-burn, coal and solar generation will continue to meet most incremental power demand. In March, coal and solar generation increased by 8.2 GW y/y and 4.9 GW y/y, respectively, while gas generation dropped by 1.3 GW y/y due to peaking power demand.

Upholding a bullish view, analysts said: “We see some upside risks to our Indian LNG demand forecast if the government mandates gas fired plants to run to prevent load shedding and ensure an uninterrupted power supply.”

US investment firm Stonepeak has agreed to acquire a 40% shareholding in Woodside Energy’s Louisiana LNG export project and contribute $5.7 billion towards the project’s capital expenditure. Woodside CEO Meg O’Neill called the transaction a material step towards readiness for FID.

The head of the German energy regulator BNetzA, Klaus Müller, disagrees with the proposal of the European Union to extend gas storage target until 2027. The mandated 90% filling level of storages by November seens to distort seasonal pricing pattern while a build-out in LNG import infrastructure offers alternatives to gas storage.

Since late 2024, gas prices for summer delivery have been trading at a premium to winter – a reversal of typical seasonal pricing. Critics blame this on the mandatory storage goals, arguing they reduce market flexibility and are skewing market signals.

Speculative long positions at the Dutch TTF gas trading hub have increased recently, fuelling concerns that traders are betting on government support for storage refills.

BNetzA President Müller find this trend worrying: “It makes me nervous. It doesn’t inspire confidence that everyone is acting responsibly,” he said, arguing the EU storage goal incentives are misaligned, costly and distort the behaviour of free markets.

The EU had introduced the 90% gas storage filling mandates prior to the winter season in 2022 when Russian gas imports collapsed, but critics say the rules are no longer adapt to today’s market dynamics. As Germany’s coalition talks continue, Müller wants to raise the issue directly with the country’s next energy minister.

EU Regulators uphold storage mandates

Over in Brussels, policymakers have a different view: Amending EU Regulation, published on Wednesday last week, proposes to extend the gas storage requirements by another two years, arguing this would be needed to deliver on the REPowerEU plan which focusses on expanding underground storage capacity of gas, upgrading and extending LNG infrastructure; and diversifying both sources and routes of pipeline gas.

"To deliver on these objectives, the extension of some of the measures, mainly the November gas storage filling target, adopted previously for a limited period of time, is necessary," the regulatory document reads.

Gas-storage facilities provide for 30% of the Union’s gas consumption during the winter months, and EU policymakers are convinced the 90% filling rate is a “necessary and appropriate level" to ensure security of supply.

“The European gas market remains tight. The competition for global LNG supplies has increased and exposure to price volatility is stronger than before.”

“The gas price development during the 2024/2025 winter may confirm the trend,” EU policymakers argue, underlining: “In such situation, the role of gas storages remains paramount.”

LNG as a marine fuel is gaining traction, notably in the very large crude carrier (VLCC) segment where 21 vessels are in service and 14 on order, Lloyds Register finds. Four of these VLCCs were built by Hanwha Ocean, as part of the ‘Neptune project’, on behalf of Advantage Tankers.

Deutsche ReGas has succeeded in gaining permission to restart reloading LNG tankers at its Mukran floating regas and storage unit (FSRU). The environmental ministry had forbidden the practice in the autumn, arguing reloading was not covered by the terminal’s original permit.

U.S pipeline operator William has commissioned two Transco projects – the Southeast Energy Connector in Alabama and the Texas to Louisiana Energy Pathway along the Gulf Coast. The fully contracted expansions help deliver additional volumes to LNG exports facilities along the Gulf Coast.

Production in the Permian Shale, one of the largest U.S. unconventional oil and gas plays, is set to rise as the Matterhorn Express Pipeline ramps up facilitating greater gas flows to liquefaction facilities along the Gulf Coast.

South Korean utility SK GA Ulsan has started operations of a 1.2 GW combined-cycle power station that can run on LNG and liquefied petroleum gas (LPG). Dual-fuel capability allows the plant operator to optimise fuel costs while guaranteeing stable electricity supply for 2.8 million households in the Korean port city.

Taiwan's state-owned energy company CPC Corp is considering investing into the Alaska LNG export project, having signed an initial offtake agreement with AGDC to buy LNG from the venture. The deal was signed on a tour of Alaska’s Governor Mike Dunleavy across Asia, seeking additional investors for the $44 billion Alaska LNG project.

Cost overruns and limited firm offtake had for long delayed the Alaska LNG venture – but now the project became a priority of the US Trump administration. Gov. Dunleavy and senior officials from Alaska Gasline Development Corporation (AGDC), a state entity developing the liquefaction project, are currently touring Asia with the aim of securing firm offtake agreements and private investment.

Apart from Taiwan, utility buyers in Japan and South Korea have also been approached to step up their LNG imports as the United States seeks to balance its trade deficit with these countries.

The letter of intent (LoI), signed by CPC Corp, is not binding but could sway further Asian LNG buyers to sign on for firm offtake of Alaska LNG. As part of the LoI deal, CPC wants to invest in the export project though the exact amount is still subject to discussions.

Firm offtake its vital for project developers to reach financial close on the $44 billion Alaska LNG project, one of the most expensive liquefaction projects in the world. The venture has been government funded after ExxonMobil, ConocoPhillips, and BP backed out in 2016 citing cost concerns and headwinds from environmentalists.

Phase 1 of Alaska LNG focuses on construction of the pipeline to deliver North Slope gas to interior and southcentral Alaska and resolve energy shortages on Cook Inlet. Infrastructure to liquefy the gas and export it will be developed in Alaska LNG Phase 2.

Feedgas for Alaska LNG is meant to be sourced from Prudhoe Bay and Point Thomson fields. These fields will produce some 3.5 billion cubic feet of gas per day. The proposed liquefaction terminal in Nikiski, southwest of Anchorage is designed to process, store and transport up to 20 million tons per year (mtpa) of LNG.

Realisation of the gas pipeline, for starters, has gained traction after Glenfarne in January teamed up with AGDC agreeing to jointly Alaska Export Facility, Pipeline, and a Carbon Capture facility. Moreover, Glenfarne and ENSTAR Natural Gas Company also have agreed to advance an LNG import project utilizing the Alaska LNG export site.

Should the massive Alaska LNG venture go ahead, it would be Taiwan’s geographically closest source of US LNG given that cargoes from Alaska do not need to transit the Panama Canal to reach Asia.

Egyptian Natural Gas Holding Company (EGAS) is understood to have set a $14/MMBtu cap on spot LNG purchases this summer in response to rising prices in the Atlantic Basin. An additional $2/MMBtu premium is being offered if vendors agree to get payment deferred by one year.