The week of 12–19 July delivered a textbook reminder that "high renewables" and "low prices" don't always travel together. Tasmania spent much of the week sitting on renewable penetration between 85% and 97%, courtesy of strong hydro and wind output, yet regional prices frequently climbed rather than fell — a sign that network constraints, not generation adequacy, were doing much of the price-setting.
Mainland NEM pricing was choppier than the fortnight prior. Early in the week, SA1 and VIC1 both spent extended periods in negative territory driven by wind oversupply, while NSW1 and QLD1 saw brief negative excursions during low-demand early morning windows. By mid-to-late week, prices firmed materially across the mainland — VIC1 and NSW1 both averaged in the $86–99/MWh range on 15–18 July, a sharp turnaround from sub-$25/MWh averages just days earlier.
The standout event of the week was an extreme TAS1 price spike to $23,200/MWh on 13 July, occurring despite roughly 3.2 GW of hydro, wind and gas capacity online — underscoring how transmission constraints can override apparent generation adequacy. WA1 continued to trade at a persistent premium to the NEM mainland throughout the week, a pattern that's become a recurring feature of this market.
Regional average prices swung widely across the week. VIC1 opened at just $7/MWh (12 July) before climbing to $99/MWh by 16 July. SA1 moved from an average of −$6/MWh on both 12 and 13 July to $116/MWh by 15 July — one of the sharpest week-on-week reversals in the dataset. NSW1 held a steadier band, averaging $42–97/MWh across the week, while QLD1 stayed relatively contained between $41/MWh and $79/MWh.
Negative pricing was a recurring theme in the first half of the week. VIC1 recorded a floor of −$757.07/MWh during a volatile 13 July session, alongside a −$181/MWh sustained event, both linked to high wind output (3,000–6,800 MW) combined with brown coal generation. SA1 posted a −$204/MWh minimum on 13 July and a −$101/MWh sustained event during a period dominated by wind (1,322 MW) and solar (342 MW). QLD1 saw several minor negative-pricing episodes (down to around −$3.50/MWh) typically overnight, when solar, wind and black coal output combined to outstrip demand.
WEM/WA1 note: Western Australia continued to trade well above NEM mainland levels all week, with daily averages ranging from $90/MWh (15 July) up to $152/MWh (12 July) and a peak of $364/MWh recorded that same day. A moderate price spike to $252.50/MWh hit the WEM at the 04:10 interval on 17 July, a sharp 10% jump from the prior interval as prices climbed steadily from $161.75/MWh over the preceding 25 minutes. WA1's pricing profile remains structurally elevated relative to the NEM, reflecting its distinct market design and generation mix.
Tasmania was the week's renewable story, registering penetration levels of 85.6%, 87.2% (twice), 90.4%, 91.6%, 91.7% and 91.8% across various evening periods, driven by hydro output ranging from roughly 990 MW to over 4,000 MW combined with wind contributions between 99 MW and 642 MW. Notably, several of these high-renewable windows still saw prices rise — for example, TAS1 prices climbed from $21.16/MWh to $107.78/MWh on 15 July despite abundant hydro and wind supply, reinforcing that renewable abundance and constraint-driven pricing can coexist.
South Australia also posted standout renewable figures, including 97.1% penetration on 13 July driven by wind generation of 1,437.57 MW, and 85.0% on 18 July with wind at 1,083 MW. These periods were generally associated with negative or subdued pricing, consistent with SA1's wind-heavy generation mix during low-demand windows.
Gas hub prices eased modestly through the week. STTM Sydney fell from $11.31/GJ (14 July) to $10.80/GJ (19 July), while STTM Brisbane drifted down from $11.42/GJ to $11.05/GJ over the same period. STTM Adelaide held in a tight $10.54–$11.06/GJ band. Victoria's DWGM was the softest performer, sliding from $10.50/GJ (17 July) to $10.05/GJ (14 July), consistent with milder demand conditions.
Certificate markets showed a clearer trend: LGC prices continued their pullback from the late-June peak of $8.50 (week ending 26 June), easing to $7.00 (3 July), $5.25 (10 July) and $5.05 for the week ending 17 July — a steady moderation after several weeks of elevated pricing.
With Tasmania's recurring transmission constraint likely to persist, expect continued price volatility in TAS1 independent of renewable output levels. WA1 should remain structurally elevated relative to the NEM mainland, and energy managers should watch for further overnight negative-pricing windows in SA1 and VIC1 should wind output remain strong. Gas hub prices look set to stay range-bound in the low-$11/GJ area barring a material demand shift, while the LGC market's recent softening bears watching for buyers timing certificate procurement.
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