It was a week of two distinct market personalities across the NEM. The first half (2–4 August) traded in a moderate band, with VIC1 even averaging negative territory (-$2/MWh) on 2 August amid strong wind output. But from 5 August onward, prices lifted sharply across every mainland region — SA1 peaked at an average of $171/MWh on 5 August with a maximum of $359/MWh, while NSW1, VIC1 and QLD1 all pushed through $100–$140/MWh averages mid-week. By 8 August, the market had swung back the other way, with SA1 and VIC1 averaging just $7/MWh and $6/MWh respectively as wind generation flooded the southern states.
Tasmania's week was defined less by demand-side swings and more by a persistent network constraint. The T_BLINK_TV_NGZ constraint bound repeatedly through the week (2, 7 and 8 August), at times carrying a shadow price of $8.352 million/MWh — an extreme marginal value that speaks to the severity of the transfer limitation rather than typical scarcity pricing, and one that pushed TAS1 spot prices into brief spikes even as underlying hydro and wind supply remained abundant.
The Western Australian market, by contrast, held a firmer and more consistent premium over the NEM for most of the week, reflecting the WEM's separate supply-demand balance and lack of interconnection to the eastern grid.
Mid-week was the standout for volatility. SA1 hit a weekly high of $359/MWh on 5 August (average $171/MWh for the day), with VIC1 ($275/MWh max), TAS1 ($450/MWh max on 6 August) and NSW1 ($312/MWh max on 6 August) all recording sharp peaks. QLD1 posted its widest range of the week on 5 August, swinging from -$25/MWh to $212/MWh. By the weekend, the mood had flipped: SA1 and VIC1 both averaged in the single digits on 8 August, with minimums of -$12/MWh and -$8/MWh respectively, before SA1 recorded further brief negative pricing on 9 August (-$1.02/MWh) alongside 95.4% renewable penetration.
The WEM held a firm premium over the NEM through most of the week, with daily averages climbing from $99/MWh (2 August) to a peak of $146/MWh (6 August) before easing back to $99/MWh by 8 August. Two notable spikes were recorded: $261.49/MWh on 5 August (an 80% jump within a single interval) and $337.87/MWh, both during evening demand periods. WA1's weekly maximum of $338/MWh underlines that price volatility isn't confined to the interconnected eastern states.
Wind was the standout renewable story of the week, particularly in South Australia and Victoria. SA1 recorded renewable penetration of 97.8% on 8 August, driven by wind output of 1,847 MW, with prices collapsing from $9.65/MWh to just $0.01/MWh within a 15-minute window. A further high of 95.4% was logged on 9 August, and 85.2–85.4% readings appeared earlier in the week on both 3 and 7 August. Tasmania's hydro fleet delivered consistently high renewable shares throughout, with readings of 85.6% (5 August), 90.1% (6 and 7 August) and 90.5% (9 August), generally underpinned by hydro output above 1,000 MW supplemented by wind.
These high-renewable periods repeatedly coincided with negative or near-zero pricing across SA1, VIC1, TAS1 and, at times, QLD1 and NSW1 — a pattern consistent with oversupply conditions during low-demand overnight and early-afternoon windows rather than any single fuel type being at fault. Brown coal output in VIC1 (2,500–3,150 MW) frequently ran alongside high wind and solar generation during these negative-price windows, illustrating how baseload and variable renewable output can jointly contribute to oversupply signals.
Eastern gas hubs eased gently through the week. STTM Sydney fell from $11.24/GJ (4 August) to $10.50/GJ by 9 August, Adelaide moved from $11.20/GJ to $10.50/GJ, and Brisbane softened from $11.38/GJ to $10.61/GJ. Victoria's DWGM held a similar range, trading between $10.00/GJ and $10.70/GJ across the week's available readings, settling around $10.24/GJ on 7 August.
Large-scale Generation Certificates continued their recent climb, with the weekly price rising to $8.00 for the week ending 7 August, up from $6.45 the prior week and $5.05 as recently as mid-July — a notable upward trajectory over the past month, though certificate prices remain within their broader 2026 trading range.
FCAS costs stayed largely subdued across all eight services this week. RAISEREG was the highest-value service at an average of $3.73/MWh, with LOWERREG averaging $1.29/MWh; the remaining regulation and contingency services (RAISE6SEC, RAISE60SEC, RAISE5MIN, LOWER6SEC, LOWER60SEC, LOWER5MIN) all averaged below $0.25/MWh. No material FCAS price spikes were evident in the weekly averages despite the constraint events noted above.
With wind generation running strong across South Australia, Victoria and Tasmania, energy managers should continue to expect intermittent negative pricing during overnight and shoulder periods, particularly in SA1 and VIC1. The Tasmanian transmission constraint bears watching — its repeated appearances through the week suggest it may recur under similar network conditions. On the WEM, evening demand-driven spikes remain a feature worth monitoring for exposed load. Gas hub prices look set to hold near current levels barring a demand shift, while the recent upward momentum in LGC pricing is one for certificate buyers and surrender planners to keep an eye on heading into the new week.
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