The short version is this: the southern states are still short of gas from around the middle of this decade onward, the big new domestic sources everyone points to are either years away or stuck in a regulatory queue, and the LNG terminals at Gladstone keep pulling on the same pipeline network that Victoria and South Australia rely on for winter heating. None of that is new. I wrote a version of this paragraph three years ago. The numbers have moved a little, the argument hasn’t moved at all.
Agree on the units first, because gas debates are where journalism goes to get sloppy. We’re talking petajoules a year for supply and demand, not tonnes, not megawatts, and definitely not “gas” as some undifferentiated blob that includes LNG cargoes bound for Japan and the stuff that heats a flat in Fitzroy. Conflate those and you’ll end up arguing past the person next to you, which is most of what happens at gas conferences anyway.
What AEMO’s gas outlook actually says #
AEMO publishes the Gas Statement of Opportunities each year, and it has been telling a consistent story since well before I started covering this beat: Bass Strait production is declining faster than the market likes to admit, Victoria’s remaining conventional fields are maturing, and without new supply or new pipeline capacity from the north, southern states face the prospect of gas shortfalls in peak winter periods this decade. The exact shortfall numbers move around release to release depending on demand assumptions and how much LNG diversion the modelling allows for, and I’d rather point you to AEMO’s own GSOO publication than quote a figure that will be stale by the time this runs. The direction of travel hasn’t changed in years: less local supply, same or growing demand from gas peaking plants and industry, and a pipeline network built for a different era of the market.
What has changed is the framing. A few years back this was mostly a “will the lights go out” story. Now it’s increasingly a grid-firming story, because gas peakers are doing more of the heavy lifting on the days when wind and solar don’t show up and the batteries haven’t scaled to cover it yet. We’ve covered that swing in why wholesale electricity prices swing so violently, and gas is a big part of why those swings happen where they do.
Narrabri, Beetaloo, and the supply side that still isn’t there #
Santos’s Narrabri project in northern New South Wales is the case study everyone reaches for, and for good reason. It’s been through the assessment process for the better part of a decade, cleared its major state approvals, and still hasn’t produced commercial gas at the volumes originally proposed. We went through the detail of that standoff, and Santos’s parallel carbon capture bet at Moomba, in an earlier piece on Santos: Moomba’s carbon bet and the Narrabri gas standoff, and the short version there holds: approvals are not the same as gas in the pipe, and northern NSW gas was never going to arrive fast enough to change this decade’s numbers even under a best case.
The Northern Territory’s Beetaloo Basin gets talked up as the next frontier, and it may well matter for the 2030s. But it needs pipeline capacity south that doesn’t fully exist yet, and it needs the sort of capital commitment that has been slow given how contested the approvals process has been. I’d treat any Beetaloo production timeline that promises meaningful east-coast volumes before the end of the decade with a fair bit of scepticism. Basin development in this country has a habit of running long, and Narrabri is the recent proof.
The domestic reservation argument, again #
This is the bit that never actually resolves. Every winter someone in Canberra floats a domestic gas reservation scheme along east-coast lines similar to Western Australia’s, where a slice of new production is quarantined for local users rather than exported. WA’s policy has kept its domestic gas price well below the east coast’s for years, and it’s a fair comparison to make. But the east coast isn’t starting from a blank paddock the way WA’s north-west shelf projects were when that policy was designed; the export contracts at Gladstone were signed, financed and built around expected LNG volumes, and unwinding that after the fact runs into exactly the kind of investor-certainty argument the gas majors make every time it’s raised.
The ACCC’s ongoing gas inquiry work has kept documenting the price gap between what east-coast users pay and what a genuinely competitive domestic market would produce, and federal governments have leaned on heads-of-agreement style deals with the big three Gladstone exporters rather than a hard reservation mechanism. My honest read is that this compromise approach has worked reasonably well as a stopgap and badly as a long-term fix. It relies on goodwill and periodic renegotiation rather than a rule, and rules are what markets actually plan investment around.
LNG exports and the pull on the same pipes #
Here’s the bit that gets lost in the domestic-versus-export framing: the three LNG projects at Gladstone were built to process more gas than the coal seam fields feeding them can reliably produce on their own, which is precisely why they draw on the same pipeline network that also supplies Sydney, Melbourne and Adelaide. That’s not a conspiracy, it’s a design consequence of how those projects were approved and financed in the early 2010s, when domestic demand forecasts looked different. It does mean that a cold snap in Melbourne and a contractual obligation to a buyer in Japan can end up competing for the same molecules on the same day, and the market mechanism sorting that out is price, which east-coast households and manufacturers feel directly.
I don’t think that makes the exporters villains. They built what they were approved to build, under contracts that were legal and, at the time, seen as good for the state royalties and the national accounts. But it’s worth being plain about the structural tension rather than pretending the market design is neutral. It isn’t. It was built for a world with more spare gas than currently exists.
Where this leaves the grid, not just the gas bill #
The gas story and the electricity story have become the same story, and that’s the part I think gets underweighted in the domestic reservation debate. Gas peaking plants are a genuine part of the firming mix behind the renewable build-out, alongside batteries and pumped hydro, which we’ve compared properly in pumped hydro vs big batteries: which firms the grid. If gas supply tightens and gas prices stay elevated, the marginal cost of firming rises with it, and that shows up in wholesale prices on the exact still, cold evenings when the grid needs peaking capacity most. It also complicates the economics behind projects competing in the Capacity Investment Scheme, something we’ve flagged before in is the Capacity Investment Scheme quietly picking winners — a scheme built to firm a renewable grid still has to answer for what happens when the backup fuel itself is short.
Alinta, which still runs significant east-coast gas and coal generation alongside its retail book, is a useful bellwether here; its own strategy, which we looked at in Alinta Energy: the quiet giant still burning coal, is essentially a bet that gas and coal plant stay commercially relevant through this decade precisely because the renewable firming isn’t there yet at scale. Heavy industry users covered under the Safeguard Mechanism, discussed in the Safeguard Mechanism and heavy industry: who’s actually paying, are exposed to the same gas price pass-through, on top of their carbon obligations. It’s a genuinely awkward stack of costs landing on the same manufacturers.
An observation from the Perth end of the map #
I’ll admit a home-state bias here. Watching this from Perth, where the domestic reservation policy has kept prices meaningfully lower for two decades, it’s hard not to conclude the east coast built itself into a structural bind that WA mostly avoided by legislating the reservation rule before the export projects were locked in, not after. That’s not a subtle policy insight, it’s just sequencing, and it’s the sort of thing that’s obvious in hindsight and politically brutal to fix retroactively. The AER’s own market monitoring keeps confirming the price gap is persistent rather than cyclical, which tells you this isn’t a supply blip that solves itself once one basin comes online.
None of which means Narrabri, Beetaloo or further Bass Strait investment don’t matter. They do, and new supply genuinely helps at the margin. But the honest framing is that new domestic gas supply is a partial answer to a problem that’s substantially a design and contracting problem, not just a geology problem. I don’t think that changes with one more project approval, however welcome. It changes with either a harder reservation rule or a faster build-out of the storage and battery capacity that lets the grid need less gas on the worst nights in the first place — and that second path is, on the evidence so far, moving quicker than the gas policy debate is.
— Tom Fitzgerald, Baseload & Fuels Correspondent
Photo by Tim van der Kuip on Unsplash