Energy Market Update: September 2026

Before the numbers

August looked cheap. Power prices came in 30 to 61% below the same days last winter, right across the grid, and on the face of it that is great news. It is also not the whole story: last winter was expensive, so this one looks better by comparison than it really was.

Gas is the same story in reverse. The export price in the headlines is around $26 a gigajoule, but the contracts actually being signed for 2027 sit at $12 to $14. Neither the scary number nor the cheap one is the one your business will pay.

That is the theme this month: the numbers in the news are rarely the numbers on your contract. Below, we walk through what actually moved in August, what it means if you have a renewal coming up, and the short list of things we are watching from here. And if anything in here lands close to a decision you are facing, get in touch - that is what we are here for.

The month in three numbers

• Spot power: 30 to 61% below the same days last winter, in every region.
• 2027 gas: contracting at $12 to $14/GJ against a $26 export benchmark.
• Iona storage: 13.42 PJ at 25 August, the second-highest late-August level in eight years.

The backdrop

The forward market fell through June and July, then recovered most of it in August, ending the period roughly where it started. Gas moved in the opposite direction.

Since our last update in May, the Strait of Hormuz has been disrupted for most of 2026, with the US blockade reimposed on 13 July. Brent went through US$100 on 23 July and was back to US$87.51 by 26 August. The Federal Government's domestic gas reservation, requiring LNG exporters to supply domestically an amount equivalent to 20% of their exports from 1 July 2027, completed its draft design consultation on 30 June.

Electricity market

Every NEM region was cheaper this August than last: New South Wales 33.0% lower, Queensland 30.3%, South Australia 32.6%, Victoria 47.0% and Tasmania 61.1%. All comparisons run over the first 25 days of each month, measured like for like against the same window in prior periods.

Two things are worth saying before you use those numbers. The first is the base. Winter 2025 was expensive, and a soft winter measured against an expensive one produces a headline that overstates how cheap the market is in absolute terms. This was the cheapest August in the three years we track, but it was not the cheapest month: seven months since January 2024 have been cheaper in New South Wales and fourteen in Victoria.

The second is that this was not a demand story. Load across the five regions moved between minus 3.8% and plus 7.5% year on year, so what changed sits on the supply side. The clearest part of it is the battery fleet: the AER reported on 20 August that grid-scale capacity rose from 2.2 GW at the start of 2025 to 6.1 GW by year end, and that battery charging and discharging together set the wholesale price in 16.3% of NEM intervals across that year, against roughly 1% in 2021. The daytime effect shows in our own numbers too, with negative prices in 11.7% of August intervals in Queensland and Victoria and 15.5% in South Australia. Weather, outages and hydro conditions move any single month, and separating their contribution is a piece of analysis in its own right, but the structural shift underneath is not in question.

Forward prices did move, just not in August. The New South Wales Calendar 2027 base contract sat at $87.42/MWh in mid-June, fell to $81.22 by 17 July as the Hormuz situation escalated, and recovered to $85.01 by 25 August. Across August itself all four listed regions moved less than 5%, and three of the four firmed. Read together, that looks like a market which absorbed the disruption earlier and then settled, not one that ignored it.

Spot and Calendar 2027 cover different delivery periods and are not directly comparable.

What this means for you

A soft August spot print is not a guide to what you will be quoted for 2027 or 2028, because those are different delivery periods with different seasonal composition and different risk. If your renewal is inside the next two years, the forward strip is what sits underneath the offer.

Worth noting. The Market Price Cap rose to $23,200/MWh on 1 July 2026. This is not simply annual indexation: the AEMC's 2023 reliability settings rule change reset the base to $20,700 and put the cap on a staged multi-year increase, with a final step due in 2027-28. Tasmania reached exactly $23,200 in July, the first time the new level has bound.

State by state

New South Wales

Carries the most coal in the NEM and sees the least of the midday renewable surge, with only 1.9% of August intervals below zero against 11.7% in Queensland and Victoria. Its Calendar 2027 base sits $10.20 above its August spot average of $74.81/MWh, and so does every region's, which is what a forward curve covering a full year including summer looks like against a winter month. On 13 August the Commonwealth and New South Wales committed $2.5 billion to keeping the Tomago aluminium smelter running beyond 2028, on a power purchase agreement to 2038 with close to 3 GW of new generation and firming attached. The significance is retention rather than growth: this removes the risk that a very large existing load exits the state after 2028.

Queensland

Posted the largest forward gain in the NEM at 2.9%, against the second-lowest spot price. Queensland recorded negative prices in 11.7% of August intervals, consistent with periods of high renewable output and low operational demand, and did not record one interval above $300.

South Australia

The only region where the forward fell. The shape is worth more attention than the level: across August our futures feed reported no traded volume at all for the South Australian Calendar 2027 contract, while New South Wales, Queensland and Victoria all recorded volume on multiple days from the same source. Treat the South Australian settlement price as a weaker signal than its equivalents. The spot distribution was also wide: eight intervals cleared $300 while the month's minimum was minus $496.77/MWh. That combination is cheap on average and expensive at the edges, and the two need hedging separately.

Victoria

Stayed the cheapest mainland strip by a wide margin despite 7.5% more demand year on year. The New South Wales to Victoria Calendar 2027 spread was $21.82/MWh at 25 August. For anyone running load in both states, that spread is where the contracting decision lives.

Tasmania

Recorded the largest fall in the country, to $55.54/MWh from $142.60/MWh over the same days last year. Basslink converted to a regulated transmission asset on 1 July 2026 following the AER's final revenue determination in March, so its cost now comes through regulated revenue instead of merchant bidding. Through 2025-26 Basslink was bidding in the $20 to $30 range and often higher, so the change is real. We would need interval-level analysis to prove exactly how much, and hydro conditions and mainland prices will have played a part as well.

Gas market

East coast hub prices averaged $11.01/GJ in Sydney, $11.15/GJ in Brisbane and $10.90/GJ in Adelaide across 1 to 25 August, below last winter. The Victorian DWGM averaged $9.91/GJ, though we only have clean data for 12 to 25 August, so treat that one as indicative. Gas-powered generation fell 24% in July on both a monthly and an annual basis, to 7.59 PJ, with batteries increasingly displacing some gas and hydro during peak periods.

Iona, because we told you in May to watch it

Iona underground storage sat at 13.42 PJ on 25 August, down from 15.27 PJ at the end of July. Taken alone, a second month of drawdown heading out of winter looks like a problem. Against the record it isn't one.

This is the second-highest late-August reading in eight years, behind only 2023, and above the level in six of the seven preceding years. The 12.1% July to August decline is unremarkable and milder than last year's 20.9%. Iona draws down through the back half of winter every year and refills from spring, so August was never when a refill was due.

We flagged this in May as the number that would set southern winter risk into 2027, and the answer has come back better than the winter drawdown on its own suggested. One correction to how we put it in May: we said a soft spot market weakens the incentive to inject, and that is not right. What drives injection economics is the spread between the injection cost now and the withdrawal value later, alongside storage charges, injection rights and each participant's portfolio position. Cheap gas today makes filling storage cheaper, not less attractive.

Worth being precise about what the number means, too. Iona is a system buffer for Victoria and South Australia, not cover held on behalf of buyers generally. Storage capacity is concentrated among a small number of gentailers (the big combined generator-retailers), so a healthy facility total does not translate into protection for any particular portfolio.

What this means for you

The near-term physical balance is more comfortable than it was in 2025. That is a narrower statement than it sounds, and it should not be read across to contract prices.

What gas is actually contracting at

The ACCC's short-term LNG netback stepped up again this month. September 2026 settled into the historical series at $25.74/GJ, and the forward curve published on 17 August, based on prices observed on 14 August, opens at $26.29/GJ for October delivery and holds above $25 through to February 2027.

That number is an export-parity reference. It is what a producer at Wallumbilla could realise by exporting a gigajoule after liquefaction and shipping costs, and the ACCC is explicit that it "is not the sole factor that influences domestic prices". It does not set a floor, and it is not a delivered price paid by anyone.

For a multi-year domestic contract the more relevant series is the ACCC's medium-term oil-linked netback, which sat at $14.23/GJ for Year 1 and $13.05/GJ for Year 2 as at 31 July 2026. And the contracting evidence itself sits in the same territory. In its June 2026 interim report the ACCC recorded 2027 supply offers from producers to retailers averaging $13.65/GJ, retailer offers to C&I users averaging $14.13/GJ, and executed 2027 agreements around $12.44 to $12.92/GJ.

So the honest read is this. Domestic spot near $11 and a short-term netback near $26 are measuring different things at different points in the chain, and neither is the number you will be quoted. The market is contracting 2027 gas at $12 to $14, and it has been doing so while the short-term netback climbed. Watch the September contracting round for whether that holds.

What this means for you

The genuine risk over an 18-month horizon is not netback convergence. It is supply. The ACCC's June assessment has the east coast well supplied through Q4 2026, with a surplus of between 13 and 20 PJ depending on how much uncontracted gas LNG producers export, but flags a risk of southern shortfalls in the second and third quarters of 2027 on the same variable. That is the exposure worth building a position around.

What we're watching

1. September contracting evidence

Whether 2027 offers hold in the $12 to $14 range while the short-term netback stays above $25. The gap between the two has widened all year, and the September round is the next real test of which one is informative.

2. Southern supply into 2027

The ACCC's flagged shortfall risk for Q2 and Q3 2027 turns on how much uncontracted gas is exported. For Victorian and South Australian buyers with renewals landing in that window, this matters more than any spot or netback print.

3. Iona through spring

The buffer is in reasonable shape going into September. Injection rates through spring will determine what Victoria and South Australia carry into next winter, and we will keep the year-on-year comparison in front of you.

4. Data centre rules

Energy ministers considered advice on 28 July about requiring large data centres to offset demand with new renewable generation and firming, and to be treated as market participants. Most jurisdictions supported the direction; Queensland and the Northern Territory did not support all of it. These are recommendations rather than obligations at this stage, with rule change requests still to run through the AEMC's own consultation and a final determination expected late October 2026.

If any of this bears on your position or a decision you have coming up, get in touch.

Frequently asked questions

Spot prices are down a third. Why isn't my renewal quote?

Because a retailer is not selling you last month, and the futures price is only one component of what you are quoted. An offer also carries your load shape, volume and shape risk, network and loss factors, environmental scheme costs, credit terms and margin. Underneath all of that sits a forward curve covering a full year including summer, which is a different product from a winter spot average.

Are prices actually low, or does it just look that way?

Both, partly. This was the cheapest August in the three years we track, but seven months since January 2024 have been cheaper in New South Wales and fourteen in Victoria. Winter costs more than spring in any year, and last winter was dearer than most, so the annual percentages read more dramatically than the underlying move warrants.

Electricity forwards were flat in August through a closed strait. Why?

They were not flat over the whole period. The New South Wales 2027 contract fell about 7% between mid-June and mid-July as the situation escalated, then recovered through August. Australian electricity prices come from domestic coal, gas, wind and solar, and crude reaches them only indirectly through LNG-linked gas costs, so the transmission is slower and weaker than headlines suggest.

Gas is $11 and the netback is $26. Which do I pay?

Neither, most likely. Those are a domestic spot hub price and an export-parity reference at different points in the supply chain. The 2027 contracting evidence the ACCC has published sits between $12 and $14/GJ, and that is the range to plan against until the evidence changes.

Should I lock in gas now?

The more useful question is whether you could move if you wanted to. If your site data is current and your volumes are understood, you can act inside the window when the contracting round opens. If they are not, the window will close while you are still assembling the tender.

Is your position ready?

Cheap power, and a gas market worth reading carefully. If you have gas or gas-linked electricity exposure expiring inside eighteen months, the difference between the export benchmark and what gas is actually contracting at is worth understanding before you go to market. Our team can work through what it means for your sites, so you can act with confidence rather than guesswork.