For most of LNG’s commercial history, the standard deal was straightforward enough. A buyer — typically a Japanese or Korean utility — signed a 20-year sale-and-purchase agreement. The price was oil-indexed, usually at 14–15% of JCC (Japan Crude Cocktail). Delivery was DES, destination restricted to designated receiving terminals. Both sides knew exactly what they were getting for two decades.
That structure built the global LNG industry. It also stopped reflecting how LNG markets actually work somewhere around 2016, when spot market liquidity first reached the point where destination restrictions became economically meaningless for many buyers. By 2025, the contract landscape has fragmented into something considerably more complicated — and considerably more demanding of buyers who once treated SPA negotiation as a procurement function rather than a strategic one.
What buyers are actually being offered now
The range of contract structures on offer in 2025 is wider than it has ever been. On one end: traditional oil-indexed SPAs, now routinely offered with destination flexibility clauses that were absent in earlier contracts. On the other: FOB contracts at US Gulf Coast facilities, priced at Henry Hub plus a fixed liquefaction fee, that require the buyer to take physical title and arrange their own shipping.
In between sits a proliferating menu:
- Hybrid-indexed SPAs that split price exposure between oil (JCC or Brent) and gas (JKM or TTF), reducing oil-price correlation but adding gas market volatility
- Short-term and medium-term agreements of 1–5 years, often used by buyers to bridge coverage gaps while assessing longer-term supply security
- Aggregated portfolio agreements, offered primarily by major integrated traders (Shell, TotalEnergies, BP), where a single agreement covers a notional volume from multiple supply sources with delivery flexibility
- Break clauses and volume tolerance bands that allow buyers to reduce or increase offtake within defined ranges — a structure that almost no traditional LNG SPA contained
The proliferation reflects competition among sellers. Supply additions from the US, Qatar, Australia, and Russia (pre-sanctions) created a buyer’s market in the 2018–2021 period, and sellers learned to offer flexibility to compete. The 2022 price crisis temporarily reversed the balance of power, but the underlying supply growth trajectory has reasserted itself.
The problem with Henry Hub-linked contracts for Asian buyers
US LNG at Henry Hub plus liquefaction plus shipping is an attractive proposition when Henry Hub is cheap. In 2020, when Henry Hub traded below $2/MMBtu, US LNG could be delivered into Asia at $5–7/MMBtu — far below oil-linked contract prices.
The catch is basis risk. Henry Hub reflects North American gas supply-demand fundamentals. An Asian utility that locks in a large Henry Hub-linked FOB volume has taken on exposure to a market in which it has no hedging infrastructure, no natural long positions, and limited ability to manage unexpected price moves. When Henry Hub spiked above $8/MMBtu in August 2022, Asian buyers with US FOB contracts found themselves paying delivered prices well above comparable oil-indexed DES volumes.
The IEEJ (Institute of Energy Economics Japan) has published several assessments of US FOB vs. oil-indexed DES economics for Northeast Asian buyers. Their 2024 analysis found that the Henry Hub plus liquefaction plus shipping structure typically delivered lower average costs over a 10-year period under base-case assumptions — but with standard deviation roughly 40% higher than comparable oil-indexed DES volumes. For a utility managing regulated tariff structures, that volatility creates real downstream exposure.
What Malaysian buyers and regional project developers should note
Malaysia sits in an unusual position relative to this contracting evolution. PETRONAS is simultaneously a major SPA counterparty as seller and, increasingly, as buyer — importing gas into Peninsular Malaysia as domestic production from Peninsular offshore fields declines. The company’s dual identity shapes how it approaches both sides of the market.
For LNG infrastructure project developers in the region considering PETRONAS as a potential offtake partner or equity co-developer, the company’s recent procurement posture is instructive. PETRONAS Gas operates regasification terminals at Sungai Udang (Melaka) and Pengerang (Johor), with a third terminal in Sabah. The company has been purchasing LNG into these terminals under a combination of long-term contracts and spot/short-term procurement.
The Pengerang Integrated Complex, developed initially in partnership with Saudi Aramco (though ownership structures have evolved), is a significant demand anchor for regasified LNG in southern Peninsular Malaysia. Project developers designing downstream LNG infrastructure in the ASEAN region should treat PETRONAS’s regasification capacity expansion as a leading indicator of Malaysian gas import growth trajectories.
South and Southeast Asian buyers: the contracting gap
India, Bangladesh, Pakistan, and several Southeast Asian buyers have a structural contracting problem. They need long-term supply certainty to justify terminal and downstream infrastructure investment. But their creditworthiness as sovereign counterparties — and their domestic pricing structures — makes it difficult to sign the large-volume, long-tenor agreements that US and Qatari sellers prefer.
Petronet LNG, India’s largest regasification terminal operator, has navigated this through a combination of long-term Qatari supply (RasGas/QatarEnergy contracts that predate the North Field expansion) and incremental spot procurement. India’s total LNG import capacity is now above 47 MTPA across multiple terminals, but utilisation remains well below capacity — constrained partly by domestic pipeline infrastructure and partly by the price sensitivity of end-use sectors.
Bangladesh presents the starkest version of the problem. Petrobangla, the state energy company, operates two FSRUs and has been largely dependent on spot LNG procurement. The combination of JKM prices in the $13–16/MMBtu range and a subsidised domestic gas tariff structure that cannot accommodate those import costs has created persistent supply gaps. The World Bank Bangladesh Energy Sector analysis noted that spot LNG affordability is the binding constraint on Bangladesh’s gas-to-power ambitions, not physical supply availability.
The European comparison
European utilities resolved a version of this problem through the 2022–2023 crisis by accepting market-indexed pricing and passing costs through to end consumers — a process that was politically painful but technically simple in liberalised markets with functional retail price pass-through.
Asian sovereign buyers operating in regulated markets with subsidised end-user tariffs cannot execute the same solution. The gap between international LNG prices and domestic gas prices is absorbed by state balance sheets rather than consumers — which constrains the volume of LNG that governments can commit to buying.
This structural difference has important implications for anyone designing LNG supply agreements with South and Southeast Asian sovereign buyers. Offtake creditworthiness depends on sovereign credit, not the buyer’s ability to generate operating cash flow at prevailing LNG prices. Lenders and sellers pricing credit risk into LNG SPAs with regional buyers should model government fiscal capacity, not utility financials.
Social media pulse
New LNG contract structures increasingly feature JKM-linked pricing. Problem: JKM liquidity is still thin compared to Henry Hub or TTF. Buyers hedging JKM exposure against physical LNG positions find the basis risk often exceeds the oil-indexation risk they were trying to avoid.
April 2025 · @BloombergNEF on X →
Southeast Asian LNG demand forecast revised upward for 2025–2030. But the supply contracting to meet that demand isn't keeping pace. Multiple countries have terminals under development with no long-term supply contracted. That's an infrastructure risk as much as an energy security risk.
May 2025 · @woodmac on X →
The decision buyers face right now
The choice facing sovereign LNG buyers in Asia in mid-2025 is essentially a bet on the forward price environment. Signing long-term contracts now — at oil-linked slopes of 12–13% or Henry Hub plus $2.5–3/MMBtu liquefaction — locks in moderate delivered costs over the period of maximum new US and Qatari supply growth.
Waiting, and continuing to rely on spot procurement, maintains flexibility but exposes buyers to a potential tightening in 2027–2030 when demand growth in China, India, and Southeast Asia could absorb the current wave of new supply more quickly than the base case suggests.
The International Energy Agency’s Gas Market Report 2025 characterises the 2025–2027 period as “the window” — when supply additions are at their maximum and contract terms are most competitive. That window does not stay open indefinitely.
Global LNG advises sovereign buyers and LNG project developers on procurement strategy, SPA negotiation, and supply portfolio structure. Reach our team to discuss your contracting requirements.