Chinese LNG Resales Top East Coast Demand as Gas Reservation Looms

Chinese firms resold an estimated 17-19 Mt of LNG in 2025, more than twice eastern Australia’s annual gas demand of 481 PJ. The gas Australia debates reserving is already moving through other countries’ trading books at a profit.

That is the central finding of the Institute for Energy Economics and Financial Analysis (IEEFA), whose report estimates Chinese companies have earned at least $1.6 billion on Australian-sourced liquefied natural gas (LNG) since 2021. In Canberra, a domestic reservation draft pulls one way, while Queensland’s preference for new supply pulls the other.

For anyone weighing LNG arbitrage in Australia as an investment or policy question, the real task is locating where east-coast gas risk and policy risk actually sit. Here is what the resale data proves, what it does not, and where that leaves your exposure.

How large is the resale trade in Australian gas?

Start with China. IEEFA’s report “From buyer to broker”, published on 24 September 2026, estimates Chinese firms earned about US$4.6 billion (roughly $6.6 billion) reselling US and Australian LNG between 2021 and June 2026.

The 2025 volume of 17-19 Mt is comparable to China’s entire LNG import volume from Australia, about 20.6 Mt. Set against eastern Australian demand, it equals roughly 925-1,034 PJ versus 481 PJ.

The scale outgrows the usual domestic frame quickly. Then comes Japan.

China’s shift from buyer to broker

Leading destinations for Chinese resales were South Korea, Japan and the Netherlands. Chinese-chartered vessels alone accounted for 8.4 Mt, and a 47% diversion rate was recorded in the first half of 2026.

Of the earnings, at least $1.6 billion (US$1.1 billion) came from Australian-sourced cargoes through the first half of 2026. IEEFA projects about $860 million from Australian-sourced resales in 2026 alone.

Japan’s portfolio resales

Japanese firms resold about 44 Mt in fiscal 2024, with Australian-origin gas making up as much as 756 PJ, around 1.7 times eastern Australia’s annual consumption. Japanese resales ran about 1.7 times its direct imports from Australia and roughly four times its purchases from Malaysia.

“40 percent of all LNG volumes handled by Japanese companies are sold elsewhere.” Sam Reynolds, IEEFA, quoted by Africa Oil & Gas Report on 5 October 2026.

Both of Australia’s biggest trading partners are on-selling surplus Australian gas. What this tells you is that these volumes are traded as portfolio assets abroad, so domestic price and supply outcomes are set by a market far larger than the east-coast one.

Why do the margins exist, and will they last?

The mechanic is simple: buy under a long-term contract, sell at spot. Because many cargoes are free on board (FOB), meaning the buyer collects them and picks the destination, the buyer can send them wherever prices are highest.

1. A buyer secures gas under a long-term contract, often priced against oil.
2. Spot prices rise in tight markets, such as after Ukraine and Middle East tensions.
3. The buyer redirects a destination-flexible cargo to the higher-priced market.
4. The buyer pockets the spread, less shipping and other costs.

IEEFA separates the drivers into two layers.

• Cyclical: the gap between contract and spot prices, which widened as geopolitical shocks tightened markets. Margins are projected to hit record levels in 2026.
• Structural: flat Chinese domestic demand set against growing long-term contract commitments, particularly US and Australian supply. Japanese trading companies, acting as portfolio optimisers, use the same flexibility.

The structural driver is LNG supply growth outpacing Chinese demand, which leaves contracted cargoes surplus to domestic needs and pushes buyers toward resale rather than consumption.

Because the capability is structural while the margin is cyclical, record 2026 profits look more like a peak signal than a permanent run rate. Any resale reservoir stays; the windfall may not.

One caution applies throughout:

IEEFA’s profit figures are modelled estimates built on price spreads and assumed flows. Confidential contract terms and shipping costs make them indicative, not audited.

Prices at home tell a related story. The Australian Competition and Consumer Commission (ACCC) found in 2024 little gas available at $12/GJ, with prices still linked to LNG netback. Low-cost gas has reportedly been sold overseas for as little as $15/GJ, though no official benchmark confirms that figure.

Reservation or new supply: what does the resale evidence change?

Two camps frame the debate, and the resale data tests each differently.

The policy positions

The federal exposure draft, released in September 2026, proposes that exporters supply up to 20% of production to the domestic market, calibrated by the Australian Energy Regulator (AER). Licence processes begin in 2027, obligations start on 1 January 2028, and existing contracts are respected. It targets about 200 PJ a year and shortfalls of up to 140 PJ, but it is not yet enacted.

Queensland has cautioned against diverting existing export volumes and favours investment in new supply. No dated Queensland statement was located, so treat that position as reported rather than documented.

IEEFA argues projects such as Narrabri and Beetaloo would be too slow to prevent shortages, and it described Narrabri as “troubled” in December 2022. Approval and final investment decision status for both could not be confirmed. The Australian Conservation Foundation (ACF) backs calibrated reservation from 2027 but warns that a mechanical percentage could entrench netback pricing.

Design choices matter as much as the headline percentage, because a domestic gas reservation scheme that leaves pricing anchored to export parity may secure volumes without delivering the relief households and industrial users expect.

What precedent suggests

Western Australia’s 15% reservation for new LNG capacity is credited with more stable domestic prices alongside substantial exports. The 2017 Australian Domestic Gas Security Mechanism lets Canberra direct exporters to limit exports when a shortfall is forecast.

Indonesia is the cautionary case: domestic obligations and occasional export bans protected supply but raised investor concerns about policy predictability.

The resale evidence strengthens the argument that gas exists but is not reaching Australian buyers. It does not prove reservation alone would lower prices, and you should hold both conclusions together.

What this means for east-coast gas exposure

Four risk categories emerge: policy intervention, export contract reliability, netback-linked pricing and project timing.

Two basics help. LNG netback pricing ties domestic prices to what exporters could earn selling abroad, minus liquefaction and shipping costs. A petajoule (PJ) is one million gigajoules (GJ), so 481 PJ is 481 million GJ.

LNG netback pricing: a domestic gas price benchmarked to the export-parity value of the same gas, after deducting costs of getting it to overseas buyers.

The supply backdrop is tight. The Australian Energy Market Operator (AEMO) issued a system-wide threat notice on 19 June 2024, and its 2024 Winter Gas Outlook identified a shortfall of about 90 TJ/day, falling to about 55 TJ/day after mitigation. CSIRO notes southern shortfalls are likely from 2025-2026, and the ACCC says the shift to short-term sales challenges users needing long-term certainty.

The supply backdrop rests on east coast gas market fundamentals, where declining legacy fields, constrained southern supply and a tightening contract book leave domestic buyers exposed to export-parity pricing.

For an investor, the arbitrage story raises political pressure on export volumes while supply timing risk remains for new fields. Exposure to either side needs its own scenario.

Signposts to watch:

• Whether the reservation legislation passes, and in what form
• How the AER calibrates the percentage
• Final investment decisions on new east-coast supply
• Spreads between contract and spot prices

IEEFA’s figures are indicative, and the scheme could change before it becomes law.

Weighing the resale evidence before the reservation law lands

The resale trade is large and appears structural, while the margins driving it are cyclical. The policy fork stays unresolved, with evidence on both branches.

Remember that the profit figures are modelled estimates and the legislation is not enacted. Over the coming months, the useful tests are the final shape of the draft, the AER’s calibration, and whether spot-contract spreads narrow.

This article is for informational purposes only and should not be considered financial advice. Investors should conduct their own research and consult with financial professionals before making investment decisions. Financial projections are subject to market conditions and various risk factors, and forward-looking statements are speculative and subject to change.