AEMO’s most recent gas statement of opportunities puts the first material east-coast shortfall risk in the back half of this decade, assuming a cold winter lines up with low wind output in the southern states. That’s not a new sentence. It’s close to the same sentence AEMO published two years ago, and the one before that, with the date quietly rolling forward each time the industry does just enough to avoid the cliff. I’ve now read enough of these documents back to back that I can recite the caveats from memory, which probably says more about the pattern than any single number in them.
Agree on the units first, because this debate gets muddled fast. East-coast gas supply isn’t one market. It’s a Queensland LNG export complex at Gladstone drawing on Surat and Bowen Basin gas, a southern market built on Gippsland and Cooper Basin production and increasingly on imports, and a Moomba-to-Sydney pipeline network trying to move molecules between the two when the weather or the market calls for it. When someone says “Australia has plenty of gas” they usually mean the first bit. When the AEMC or a Victorian gas retailer says there’s a shortfall coming, they usually mean the second. Both can be true at once, and for years now, both have been.
What AEMO’s winter numbers actually say #
The gas statement of opportunities models peak-day demand against contracted and uncontracted supply, pipeline capacity, and the behaviour of the three Gladstone LNG trains: QCLNG, GLNG and APLNG, which between them have first call on a huge share of Queensland’s gas production under their own supply contracts. The southern states’ domestic shortfall risk shows up on the coldest days, when heating demand in Victoria and South Australia spikes at the same time Bass Strait fields are in natural decline and the Victorian government’s moratorium-era caution on onshore gas still shapes what’s available close to the biggest demand centre.
None of this is secret or contested. The AEMC’s gas market review and successive ACCC LNG inquiry reports have said versions of it for years. What’s shifted is the timing of the pinch point, which keeps getting pushed out by a mix of new supply agreements, demand response, and – bluntly – a run of mild winters that haven’t tested the system the way a genuine east-coast cold snap would.
Santos, Narrabri and the supply side nobody agrees on #
Santos’s long-running push to bring the Narrabri coal seam gas project into production sits right at the centre of this argument, and I’ve written before about how that standoff interacts with the company’s other east-coast bet at Moomba. The project has NSW planning approval, contested by landholder and environmental objections that have gone through years of assessment, and the company continues to argue it’s the most direct way to put new domestic gas into the southern market without relying on a pipeline haul from Queensland or an LNG import terminal. Opponents argue the water and biodiversity risk in the Pilliga isn’t worth the gas it unlocks, and that the real fix is demand reduction, not new supply. Both sides have been saying roughly this since the project was first proposed, and the dispute has outlasted at least two federal energy ministers.
Separately, the proposed LNG import terminals at Port Kembla and in Victoria have moved at their own, slower pace, with commercial and regulatory hurdles that have pushed timelines out more than once. An import terminal doesn’t create gas, obviously. It creates optionality, a way to bring in cargoes when domestic supply is tight and international LNG prices make that economic. Whether that optionality gets used in practice depends entirely on a price signal nobody can forecast with confidence two years out.
The export question that still won’t resolve cleanly #
Here’s the part of this argument that never quite gets settled, and I don’t think it’s going to: a meaningful share of east-coast gas production leaves the country as LNG, contracted under long-term deals signed when the export projects were financed more than a decade ago. The Australian Domestic Gas Security Mechanism gives the federal resources minister power to restrict exports if there’s a forecast domestic shortfall, and it’s been invoked as a threat more often than it’s been formally triggered, because the mere existence of the lever tends to bring LNG producers to the table with voluntary supply commitments instead.
The gas industry’s position, which Santos and others have made consistently in ASX filings and investor briefings, is that the export trains were built on contracts signed in good faith, that domestic supply shortfalls are a reservation and pipeline problem rather than an export problem, and that Queensland production has in practice supplied the domestic market through voluntary heads of agreement arrangements for years without a formal mechanism trigger. The counter-argument, made just as consistently by manufacturers and some state governments, is that a resource extracted in Australia ought to serve Australian industry and households first, full stop, and that the mechanism has been too slow and too political to act as real insurance.
I’ll be honest about where I land on this one, because it’s not a neutral question and pretending otherwise would be dishonest: the export commitments were made decades ago under a different gas market and a straight read of “contracts are contracts” undersells how much the policy settings around LNG approvals have shifted since those final investment decisions were taken. That doesn’t mean tearing up contracts. It does mean the domestic reservation argument deserves more weight than the industry’s standard answer tends to give it.
What this actually means for electricity prices #
This masthead has covered why gas keeps coming up in the firming conversation even as batteries and pumped hydro scale up, and the gas supply question matters here specifically because gas peakers set the marginal price in the NEM disproportionately often, especially in Victoria and South Australia on calm winter evenings. A tight domestic gas market doesn’t just threaten home heating bills. It flows straight into wholesale electricity prices through the peaking generators that rely on spot gas purchases rather than long-term contracts.
The Capacity Investment Scheme is meant to bring enough firmed renewable capacity online that this dependency eases over time, and the mechanism’s design has been debated in its own right. But batteries firm for hours, not days, and the multi-day wind lulls that actually stress the southern grid in winter are exactly the conditions where gas peakers still do work nothing else on the system can currently do at scale. Anyone promising that storage alone solves the winter gas question in the next few years is skipping past the duration problem, not solving it.
Victoria’s onshore gas politics, still unresolved #
Victoria lifted its exploration moratorium on conventional onshore gas a few years back but kept the ban on fracking-dependent unconventional gas in place, which leaves a fair chunk of the state’s prospective reserves untouched regardless of what Bass Strait decline curves do. The state government’s own long-term energy strategy leans heavily on electrification and offshore wind to manage demand down rather than new gas supply up, which is a coherent position but doesn’t do much for households and industrial users who need gas specifically, not just energy, in the next five winters.
I’d note the asymmetry here without pretending it’s simple: Victoria consumes a disproportionate share of southern gas demand but has constrained its own supply options more than Queensland or NSW have, which puts more weight on pipeline capacity out of the Cooper Basin and on Moomba’s expanding role than the infrastructure was originally sized for.
The scorecard, such as it is #
Production from Queensland’s CSG fields and the Cooper Basin hasn’t collapsed – reserve estimates from the geological surveys and company filings still show decades of 2P reserves nationally. The problem was never really “not enough gas in the ground.” It’s deliverability to the right market at the right time of year, at a price that doesn’t blow out household bills or industrial costs, while three LNG trains keep drawing on the same basins.
That’s a solvable problem in the sense that more southern production, more pipeline capacity, or genuine demand reduction through electrification would all ease it. It’s a much harder problem politically, because every one of those fixes has a visible loser: landholders near Narrabri, Victorian voters who elected a government that promised no fracking, or industrial gas users who’d rather not pay for new pipeline capacity through their bills.
My own read, for what it’s worth after watching this argument repeat on a roughly two-year cycle since the first gas statement of opportunities flagged southern shortfall risk: the can keeps getting kicked not because anyone’s lying about the numbers, but because every actual fix requires someone specific to accept a cost they’ve so far managed to avoid. AEMO’s modelling will keep finding a mild winter to lean on until, one year, it doesn’t.
Whether that year is 2028 or later depends on decisions that are mostly still sitting on ministers’ desks rather than in anyone’s investment plan. Worth watching Narrabri’s next approval milestone and Moomba’s expansion progress as the two clearest signals of which way this actually breaks.
– Tom Fitzgerald, Baseload & Fuels Correspondent
Photo by Christian Harb on Unsplash