LNG

The Energy Regulatory Commission (ERC) of the Philippines has approved a five-month expansion of Meralco’s power purchase agreement (PPA) with First Gas Power Corp. The deal secures 1,000 MW of electricity supply from the Sta.Rita power plant in Batangas until June 25.

British energy regulator Ofgem today approved the first £28 billion ($37.33 billion) of a total £90 billion of investment in UK power and gas network companies – including greater capabilities for LNG imports.

Thailand’s Energy Regulatory Commission (ERC) is stepping up efforts to mitigate risks posed by disrupted LNG trade flows through the Strait of Hormuz. Nearly two-thirds of Thailand’s electricity comes from gas-fired power stations which largely depend on imported LNG, making them vulnerable to supply shortages and geopolitical risk.

Developers of Freeport LNG have filed to the Federal Energy Regulatory Commission (FERC) for a 40-month extension to complete Train 4 expansion. If granted, the extension would postpone the in-service deadline from August 1, 2028, to December 1, 2031.

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.

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.

Costly investment programmes to facilitate Europe’s green energy transition are weakening the credit metrics of regulated gas and electricity networks. Moody’s Ratings hence changed the outlook of European TSOs to ‘negative’ from ‘stable’.

Transparent and established regulation still supports credit quality, but regulators struggle to facilitate infrastructure investment at an affordable cost. “If shareholders consider allowed returns or cost recovery mechanisms to be insufficient, then support will fall short of maintaining credit quality,” analysts commented.

Europe's power grids and gas network operators are hard pressed to handle the substantial growth in load-related Capex required, and planned investments, said Phil Cope, senior credit officer at Moody’s Ratings.“Pressing demands arise from the need to grid-connect more renewables and accommodate rising volumes of electricity demand other sectors, e.g. heating (heat pumps), transport (electric vehicles), and data centres, where demands for capacity will intensify to support the growth in AI,” he explained.

Capital spending has grown significantly in recent years: Five-year Capex guidance for many networks – especially electricity transmission – is at least double that of five years ago. The current regulatory framework allows many gas and power network operators to recover investment over 20 to 50 years. But analysts warn the surge in Capex dwarfs the rise to network companies’ operating cash flow and this, in turn, weakens cash-flow based credit metrics.

TenneT, the TSO handling the power grid in the Netherlands and part of Germany, has seen its five-year Capex guidance soar from €40 billion in 2023 to over €62 billion this year – with no end in sight. The Belgian/German network operator Elia, meanwhile, has seen the same Capex metric almost double from around €16 billion to €30 billion over the same period.

The French and Spanish utilities ENGIE and Iberdrola have either increased or stated their intention to rise their exposure to regulated electricity networks. Moody’s reckons this is because they aim to improve their risk profile by benefitting from the “growth in higher quality earnings” as these networks carry out their investment programs. Others, notably SSE of Scotland and the German regional utility EnBW have reduced their exposure by selling their minority stakes in their power transmission businesses in recent years.

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.”

Kinder Morgan, the largest energy infrastructure company in North America, is making preparations for the expected start in 2017 of construction work to transform the Elba Island liquefied natural gas terminal on the Atlantic coast of Georgia into an export plant.

Canada’s largest private utility FortisBC is eager to find alternative offtakers from its Tilbury LNG facility after a deal with Hawaiian Electric faltered. Expansion of the Tilbury site is now at risk - the timeline will be pushed back, if no alternative buyer can be found.