The week of 23–30 August 2026 delivered a classic late-winter mix across the NEM and WEM: mild volatility mid-week giving way to a distinct softening into the weekend. Mainland NEM regions tracked a broad arc from relatively subdued pricing early in the week (QLD1 and TAS1 averaging in the low-$50s/MWh on 23–24 August) through a mid-week peak on 26–27 August, when SA1 and WA1 both pushed average daily prices above $140/MWh, before easing back into a softer, more negatively-skewed pattern by 29 August.
Tasmania was the standout region for structural themes this week, combining some of the highest renewable penetration readings in the NEM (repeatedly above 87%, peaking at 92.1% on 25 August) with a persistent, high-value binding transmission constraint (T_BLINK_TV_NGZ) that recurred on five separate days. This is a useful reminder that abundant renewable supply and network constraints are not mutually exclusive — TAS1 prices frequently rose sharply even as hydro and wind output remained plentiful, underscoring that transmission and system security settings, not fuel availability, were the binding factor.
WEM conditions in Western Australia were comparatively firm all week, with WA1 daily averages ranging from $94/MWh to $147/MWh — consistently higher than most NEM regions — punctuated by four discrete price spikes exceeding $250/MWh. The WEM's tighter, more isolated market structure continues to produce sharper single-interval spikes than the interconnected NEM, a pattern that held true again this week.
Mid-week (26–27 August) was the pricing high point across the NEM. SA1 averaged $143/MWh on 26 August (reaching $255/MWh intraday) and $107/MWh on 27 August (touching $247/MWh), while NSW1 and VIC1 both spiked above $290–300/MWh on 27 August. By contrast, 29 August saw broad softening, with TAS1, SA1 and VIC1 all recording daily minimums in negative territory (−$35/MWh, −$32/MWh and −$34/MWh respectively) as overnight oversupply conditions took hold.
WA1 was the firmest region on the grid this week, never averaging below $94/MWh on any day. Four notable spikes were recorded: $274/MWh (24 August), $303/MWh (26 August), $307/MWh and $257/MWh (27 August), and a further spike to $352.26/MWh at the 12:05 interval on 30 August — a 161% jump from the prior interval and the sharpest single-interval move of the week. These isolated, single-interval spikes are characteristic of the WEM's standalone market design and tighter reserve margins relative to the interconnected NEM.
Negative pricing was widespread but shallow across most NEM regions in the early hours of 28–30 August, with NSW1, QLD1, VIC1, SA1 and TAS1 all recording brief excursions into negative territory (typically −$3 to −$8/MWh), consistent with overnight oversupply from renewable and baseload generation rather than any single acute event.
South Australia recorded the standout renewable figure of the week: 97.9% penetration on 24 August, driven by 1,551 MW of wind generation supplemented by 684 MW of battery discharge, with prices holding a comparatively stable $83–88/MWh band throughout. SA1 also posted 95.4% (23 August), 89.5% (29–30 August) and 89.2% (28–29 August) penetration readings, reflecting a consistently strong wind resource across the week.
Tasmania again demonstrated sustained high renewable shares, with six separate readings between 87.2% and 92.1% across the week, generally driven by hydro and wind output between 1,360 MW and 2,800 MW combined. Notably, several of these high-renewable periods coincided with rising rather than falling prices — for example, TAS1 renewable penetration of 91.6% on 28 August accompanied a price rise from around $68–78/MWh to $122–125/MWh — reinforcing that constraint and demand dynamics, rather than generation mix alone, were driving Tasmanian price movements this week.
East coast gas hub prices held a fairly narrow, stable band this week. STTM Sydney ranged between $10.50/GJ and $11.09/GJ, STTM Brisbane between $10.98/GJ and $11.68/GJ, and STTM Adelaide between $10.60/GJ and $11.10/GJ. Victoria's DWGM was the softest of the tracked hubs, easing from $10.23/GJ (27 August) to $9.65–9.67/GJ by 26–28 August. Overall, gas pricing showed no material directional trend, consistent with mild late-winter demand.
Certificate markets moved more decisively. LGC prices eased for the second consecutive week, falling to $7.25 for the week ending 28 August, down from $7.75 the prior week and off the recent peak of $8.50 (week ending 14 August). This continues a pullback from the mid-August high, though LGC prices remain well above the $5.05–5.85 range seen in mid-to-late July.
Heading into early September, expect the interplay between Tasmania's recurring transmission constraint and its high hydro/wind output to remain a key theme to watch, particularly if T_BLINK_TV_NGZ continues to bind through peak periods. WA1 has shown a tendency toward single-interval spikes throughout the month, so participants with WEM exposure should continue monitoring intraday volatility closely. On the east coast, overnight oversupply conditions and negative pricing in the early hours look set to persist given current renewable output levels, while gas hub prices are expected to remain range-bound absent any material demand or supply shift. LGC pricing will be worth watching for confirmation of whether the recent pullback stabilises or continues.
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