NEM wholesale prices halve to $74/MWh as batteries, rooftop solar squeeze out coal
Australian east coast power prices fell 47% in Q2 as battery storage and consumer generation reshape the market's volatility profile.
Wholesale electricity prices across Australia's National Electricity Market averaged $74/MWh in Q2, down $66/MWh — a 47% collapse from the same period a year earlier — according to the latest Australian Energy Market Operator quarterly data. It is the kind of number that would have been unthinkable when AEMO was suspending the entire market just months earlier.6
The scale of the decline matters because it rewrites the investment case for new generation in a market where roughly 40% of the original coal fleet has already retired. The remaining stations average 38 years in age, yet prices are falling as replacements come online faster than the old plants leave.2
East coast wholesale gas prices averaged $9.08 per gigajoule in the quarter, their lowest level since Q2 2021, driven by weaker domestic demand. South Australia was the only region to experience any material price volatility, a stark contrast to the market-wide chaos of the previous year.6
The price collapse is not a demand story. It is a supply-mix story. Rooftop solar capacity now exceeds the generating capacity of remaining coal plants, and at times meets more than 60% of all NEM demand. More than 4 million generators sit on one in every three Australian homes.2
Behind-the-meter batteries that respond to prices but are not centrally dispatched have reached 2.8 GW of capacity — the equivalent power capacity of Eraring, Australia's largest coal plant. AEMO data shows that fleet, combined with grid-scale storage, is increasingly shifting energy across the day and compressing the price spikes that once defined the market.1
The market AEMO suspended in the prior year is barely recognisable now. During the crisis period, the operator issued around 500 directions to more than 5 GW of generation plant before taking the unprecedented step of shutting the entire NEM to keep supply reliable. Extreme prices had intersected with a cold snap and generator outages.2
But that volatility drought has created its own problems. Prices have been largely subdued for months, including through the 2025-26 summer, and industry participants have noted intra-day volatility compressing while inter-day and event-driven volatility become more important. Battery storage is widely credited as the main contributor.3
Queensland shows the wind story: average wind generation in the region rose 80% to a new all-time high of 842 MW, the largest increase of any NEM region. Yet the state's coal fleet still runs, and the transition is uneven across regions and time horizons.6
CSIRO's GenCost report added to the picture in July, finding batteries are increasingly Australia's preferred technology for flexible generation as data centres drive up the costs of gas-fired generation. The report feeds directly into AEMO's Integrated System Plan, the blueprint for grid investment.4
The strategic question for traders is whether $74/MWh is the new equilibrium or a trough before the next squeeze. The remaining coal fleet is old and its exit schedule remains uncertain; the 2023 AEMO projections warned supply risks escalate in later years if coal plants retire faster than renewables and storage replace them.5
South Australia spot power was trading at A$-2.12/MWh on Friday (2026-09-04) while Wallumbilla gas sat at A$11.40/GJ. Negative prices in the day-ahead market are becoming routine, and they signal a system where renewables plus batteries can meet demand in daylight hours but still need thermal backup at night and in winter. [LIVE PRICES]
The unresolved risk is whether the investment signal from low prices arrives before the next coal exit. AEMO's ISP projections assume a build-out pace that the market has not always met. The average age of remaining coal stations keeps climbing, and each retirement shrinks the buffer.
What to watch is the next AEMO quarterly report for whether the $74/MWh average holds through the Q3 peak demand season, and whether South Australia's volatility remains isolated or spreads east as winter approaches. Battery revenue models depend on volatility; if it stays compressed, the case for the next 2.8 GW of storage gets harder to make.6