LNG import hopefuls are bullish

Hey Reader, welcome to The Energy's weekly data newsletter. This week we explore what's behind plans for Australia to import LNG.

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On its face, it seems bonkers that Australia - as one of the three largest liquefied natural gas (LNG) exporters in the world - would make plans to import the stuff for its own use.

Yet as the east coast’s traditional mainstay - the Bass Strait joint venture - steadily runs out, that’s where we are. It's a situation bolstered by Queensland LNG producers remaining resolute on exports, new domestic supplies materialising slowly and headline-grabbing fears of supply shortfalls from 2028.

But what makes aspiring LNG importers Squadron Energy and Viva Energy so confident they can absorb the high costs of liquefaction, transport and regasification to supply domestic markets at competitive prices?

The answer is a combination of the capital cost of building new north-south pipelines to ease constraints on the existing east coast gas network, the relatively low capital requirements of bringing in a floating regasification unit (FRU), and a looming oversupply of LNG.

To that you can add the extreme spikiness of Victorian demand. It can leap to more than three times average demand during early winter freezes of the kind endured in late autumn and early winter this year (and many other years).

Billions

In short, it would cost between $8 billion and $10 billion to build and expand a series of pipelines linking Northern Territory and Queensland gas fields to South Australia’s Moomba gas fields, and Moomba to Sydney and Melbourne, according to estimates by Rystad Energy for Jemena. Jemena owns the Eastern Pipeline that would carry the gas from Port Kembla to Sydney, ACT and Victoria.

More than half of that capital would be required for a new 500 terajoules/day pipeline linking the Northern Territory’s Beetaloo gas field to the Moomba-Sydney Pipeline (MSP), with just over a third required to expand the MSP and Victoria-Northern Interconnect (VNI) which links the MSP to Melbourne.

These expansions would be required to deliver new gas from the Beetaloo Basin and spot or uncontracted gas from Queensland to the southern market, which are the main alternatives to LNG imports.

*The cost of pipeline infrastructure to deliver gas south has been estimated at between $8 and $10 billion. Source: Rystad*

Primed

Even then, all local storages would have to be primed to meet extreme peaks which occur when early winter freezes coincide with wind droughts and poor winter solstice solar output.

Indeed, Victoria and South Australia have just experienced such a perfect storm of challenges for renewable energy, as they also did last year and in 2022.

At such times, daily southern (Victoria, NSW, ACT and South Australia) demand can soar from a typical 500 TJ/day to between 1500 TJ/d and 2000 TJ/d.

Pipeline expansions, increased southern production and local storage won’t be enough to cover those peaks from 2028, the LNG import proponents argue, on the basis of the Australian Energy Market Operator’s 2025 Gas Statement of Opportunities.

Victoria and the southern market depend on the Dandenong and Iona (Port Campbell) storages — which can deliver a combined 767 TJ/d — to cope with peak days.

Viva’s Geelong import terminal could add 650-750 TJ/d to that; Squadron’s Port Kembla terminal 500TJ/d. A separate proposal from Vopak for Port Phillip Bay could bring in up to 778 TJ/d.

*Ensuring sufficient gas for the southern east coast market is complicated by extreme early winter peaks. Source: AEMO, 2025 GSOO*

Glut

Squadron and Viva say the pipeline expansions wouldn’t be ready in time to meet the expected southern market shortfall in 2028, and LNG import terminals can be commissioned at a fraction of the upfront capital cost ($500 million or less).

Less capital means they can get their investments back more quickly than builders of 40-year pipelines, which could be handy if gas demand turns down sooner than forecasters expect.

At the same time, the proponents argue an expected surge of 50% in global supply of LNG by 2028 - thanks mainly to increased production in the US and Qatar - will cause a glut.

This in turn will moderate LNG prices, helping to make imports competitive with locally supplied gas.

*A surge in global LNG supply will lead to a glut, moderating prices. Source: Squadron Energy/S&P Global*

Competitive

An additional advantage for imported LNG is that peak winter demand in Australia occurs during summertime in the big Northern Hemisphere markets for gas, so pricing is sharply counter-cyclical.

Squadron says it can deliver re-gasified LNG to Sydney for $14-$18 a gigajoule - and cheaper in our winter - which would be competitive with new supply from Queensland or the Northern Territory.

Viva argues similarly for supply to Melbourne from Geelong, estimating a $10/GJ lower cost (without giving indicative pricing to customers).

*Squadron says it can deliver re-gasified LNG to Sydney for $14-$18 a gigajoule — cheaper in our winter. Source: Rystad Energy/Jemena*

What could go wrong?

As usual, plenty could go wrong.

For example, neither proponent has signed up a sufficient number of customers to make a final investment decision, after several years of pursuing projects. Squadron had to surrender its lease of a Floating Regasification Unit as a result — its FRU is currently plying its trade in the Mediterranean.

Politicians may succumb to the 'pub test' notion that a large exporter of LNG just shouldn’t also be importing it. The Albanese government is already reviewing the east coast gas market with an eye to belatedly introducing a domestic gas reservation in place of the current ad hoc jawboning system.

Customers may use LNG importers as stalking horses to get cheaper gas from Queensland, as MST Marquee head of energy research Saul Kavonic has suggested. And if a large new resource in Queensland - such as Shell's Taroom Trough - is proven, it could obviate the need to build a new pipeline to the Beetaloo Basin, lowering the cost of new east coast domestic supply.

The GSOO is an annual planning document that regularly predicts (and postpones) gas shortfalls as conditions change. For example, more rapid electrification of heating, industry and transport, and more rapid development of alternatives to gas peaking plants for long duration firming power, could mean forecast increases in gas demand simply do not materialise.

The problem for energy policymakers is they can’t count on that.