Make a reservation

The east coast gas market is hurtling towards a policy intervention deemed unthinkable even during the worst of the supply crisis triggered by Russia’s invasion of Ukraine in 2022 — reservation for domestic customers.

Tentative interventions by former and current governments sought to cajole Queensland’s three liquefied natural gas exporters to leave enough gas in the domestic market to ease the squeeze on local manufacturers and electricity customers.

But the measures lacked teeth and compulsion, became badly compromised with exemptions, and failed to materially improve the lot of gas customers.

Prices for contract gas jumped to as much as $17.50 a gigajoule in 2023 and — with the exception of small volumes of gas subject to a $12/GJ price cap agreed with the federal government — have stayed broadly between $12/GJ and $15/GJ since.

These eye watering prices — multiples of historic prices from Bass Strait that underpinned gas-intensive industries — contributed to the demise of plastics manufacturer Qenos, Oceania Glass and other less celebrated industrial firms.

Now comes the prospect of a reservation policy that Energy Edge, a consultancy, estimates could cut gas prices for local customers by 18% in NSW, 21% in Queensland and 22% in Victoria. (Western Australia has had domestic reservation for years.)

‘Sweet spot’

Energy Edge’s Gas Market Analysis was prepared for LNG exporter APLNG. It identifies a sweet spot of an extra 30 petajoules a year to be supplied by the three Queensland producers to the local market. This equates to about 80 terajoules a day, or about 6% of East Coast domestic consumption.

Managing director Josh Stabler says this amount would provide the optimal combination of maximum price reductions and minimum deterrence of investment in new production.

(The firm analysed three scenarios: gas exports from Queensland to the southern market in Spring, Summer and Autumn; electricity exports from Queensland gas generation in the depths of winter, and “no channel” — limited additional gas or electricity exports during “cold, dark and still [winter] evenings when gas pipelines and generation capacity are already fully utilised”.)

“While the constraints of the third channel limit the impact of the additional gas during the most severe market conditions, the modelling does indicates there is an effect on the average annual gas and electricity prices from the first channels to market, with 30PJ p.a. of additional gas supplies estimated to lower gas prices by A$2/GJ,” Stabler says.

How did we get here?

In a nutshell, East Coast supplies are becoming tighter, and the gas available to domestic customers is becoming more costly, for two main reasons.

First, the historic mainstay of East Coast market supply — Bass Strait — is coming to the end of its life, and total “southern production” (everything bar Queensland and Northern Territory) is steadily declining.

Maximum daily production from existing, committed and anticipated southern gas fields is expected to fall from just under 1200 TJ/day this year to around 600 TJ/day by 2029, according to the Australian Energy Market Operator’s 2025 Gas Statement of Opportunities (GSOO).

(1200 TJ/day equates to 438 petajoules a year.)

Domestic gas consumption is also easing, due to electrification of homes and businesses, the steady build out of renewable electricity and batteries which eats into gas generation, and the closure of some gas-dependent manufacturers.

Domestic consumption is expected to fall from around 500 PJ/year in 2025 to between 400 PJ/year and 450 PJ/year by 2030, according to the GSOO.

This is obviously not enough to offset a halving in southern production. And it isn’t forecast to continue, largely because demand for gas generation is expected to increase from the early 2030s, offsetting the ongoing decline in gas demand from homes and businesses.

The upshot is that if significant new supplies are not brought online, supply gaps emerge in southern regions in 2028, and get worse in the 2030s. By 2035 the gap is forecast to be between 100 PJ/year and 140 PJ/year, depending on the scenario.

A tightening domestic supply demand balance would be sufficient on its own to increase prices. But that’s not all that’s been happening. More than a decade ago Queensland LNG production opened up, and linked a hitherto isolated market to the export market.

'Pony up'

This created a major new export industry. But it didn't please everyone.

The expectation was that all three — Origin Energy's APLNG, Shell's QCLNG (QGC), and Santos' GLNG — would bring their own production to the export trade, quarantining the domestic market.

Two of the producers met this expectation. APLNG consistently sold between 120PJ/yr and 150 PJ/yr of gas (net of purchases for export) into the domestic market from 2017 to 2024, though this surplus is forecast to decline in the coming years, according to the Australian Competition and Consumer Commission’s Interim Gas Inquiry, June 2025.

QCLNG was also a net contributor to the domestic market from 2017 to 2023, and is not considered a drain on the local market because the third party gas it buys was “explicitly developed for export”, the ACCC says.

GLNG is the outlier. It bought between 120 PJ/yr and 150 PJ/yr of gas from the domestic market for export from 2017 until now, and this is forecast to continue, effectively negating the contributions of APLNG.

That’s why GLNG is the focus of the campaign for domestic gas reservation on the East Coast, although the export permitting system envisaged is likely to cover all the three LNG producers.

In the past it has been suggested that this should only apply to new projects, or existing projects when export contracts expire, which advocacy group IEEFA notes would release large volumes for domestic use. But this might not treat the producers equitably, and would be too slow for local gas users (the shortest contract — GLNG's 171 PJ/yr Korea Gas Corp deal — doesn't expire until 2031, the rest until the mid-2030s).

“They're in a tough spot. But shareholders of the other two shouldn't be bailing them out. Consumers certainly shouldn't be bailing them out. I'm sorry,” says Andrew Richards, CEO of the Australian Energy Users Association.

“I know some folks over at GLNG, they're good people, and they’re in a tough spot, but at the end of the day, they've got to pony up.”

GLNG CEO Stephen Harty wrote in the company's defence (in The Australian Financial Review) last month that it is investing $1 billion a year to grow its own gas production and reduce domestic purchases, and by 2027 will "predominantly" export its own gas and gas developed for it by Santos and other strategic partners.

Fluid variables

The challenge for policymakers is to find a solution that hits Stabler’s sweet spot — delivering material price reductions while encouraging — and not deterring — new production.

The degree of difficulty for climate and energy minister Chris Bowen and industry minister Tim Ayres is increased by the large number of fluid variables in the equation.

The accelerating rollout of batteries large and small, not to mention electric vehicles capable of two-way charging, may reduce the need for gas generation except in the deep winter doldrums. Renewable gas in large volumes — a distant prospect now — may reduce demand for fossil gas.

New southern supplies, such as Amplitude Energy’s East Coast Supply Project (ECSP+) in the Otway Basin, could bring more additional supply to domestic users than reservation for Queensland LNG producers. This production would also pour straight into APA Group’s Victorian gas pipeline, which APA is intent on expanding, rather than the severely capacity constrained North-South pipelines.

On the other hand, slower progress on any of the above — which can’t be ruled out — could make things even worse, making finding the right policy response even more critical.

With thanks to OnlyFacts​

NEM Renewables Breakdown
​Last week (18 Nov - 24 Nov) vs. same week in 2024:

• Renewables: 50.9% (+6.1%)
• Fossils: 49.1%

SWIS Renewables Breakdown
​Last week (17 Nov - 23 Nov) vs. same week in 2024:

• Renewables: 47.7% (+1.2%)
• Fossils: 52.3%

Emissions Intensity (NEM & SWIS) This month so far vs. Nov 2024​
• NEM: 472.5 kg CO₂e/MWh so far this month (-8.5%)
• SWIS: 316.0 kg CO₂e/MWh so far this month (-13.8%)