It was a lively week across the NEM, with prices trending higher through mid-week before easing back by Saturday. NSW1 and SA1 both saw average daily prices climb into the $85–155/MWh range by 13–14 August, with SA1 hitting a weekly high daily average of $155/MWh on 14 August as regional volatility peaked at $316/MWh. VIC1 and TAS1 followed a similar pattern, rising from relatively subdued conditions early in the week ($31–38/MWh averages on 9–12 August) to $78–97/MWh by mid-week, before softening into the weekend.
WA1 was the standout region for absolute price levels all week, with daily averages ranging from $102/MWh to $148/MWh — consistently the highest of any region — reflecting the WEM's tighter reserve margins and different market structure. Tasmania was the site of the week's most persistent operational story, with a major transmission constraint (T_BLINK_TV_NGZ) binding repeatedly across almost every day of the week at an extraordinary shadow price of $8.352 million/MWh, despite regional prices themselves staying comparatively moderate.
Renewable output remained strong across the mainland south-east and Tasmania, with several days of sustained negative pricing overnight and in shoulder periods as wind and solar output outpaced demand. Demand growth through the week — particularly the morning ramp in QLD1, NSW1 and VIC1 — kept spot prices firm during peak periods even as overnight troughs saw prices fall toward or below zero.
SA1 recorded the widest swings of the week, moving from a daily average of $36/MWh on 9 August to $155/MWh on 14 August, with an intraday peak of $316/MWh. NSW1 peaked at $184/MWh on 12 August, while QLD1 touched $294/MWh the same day amid tighter regional conditions. TAS1's daily average ranged from $37/MWh to $87/MWh, though intraday prices spiked as high as $320/MWh on 11 August.
Negative pricing was a recurring feature, particularly overnight and in the shoulder periods around 00:00–06:00 AEST. SA1 saw the deepest negative excursion of the week at −$101/MWh (10 August daily minimum), with further sustained negative intervals across 9–16 August in SA1, TAS1, VIC1, QLD1 and NSW1 — all coinciding with strong wind and solar output relative to demand.
The WEM remained the highest-priced region in the country all week. Daily averages ranged from $102/MWh to $148/MWh, with four separate moderate price spikes recorded: $257.34/MWh (10 August, 09:35), $266/MWh escalating past $366 (11 August, 11:20), $267.98/MWh (12 August, 11:45) and $264.32/MWh (15 August, 10:20). The 11 August event was the sharpest, a 67% jump within a single interval, while the weekly high of $613/MWh was recorded as an intraday extreme on 11 August. WA1 pricing eased somewhat toward the weekend, with the 15 August average dropping to $102/MWh.
South Australia posted several high-penetration renewable milestones this week, including 97.5% on 11 August (driven by 1,636 MW of wind), 97.1% renewable penetration with carbon intensity of just 0.0141 tCO2/MWh on one morning, and 91.1% on 16 August with wind output of 1,283.82 MW. Tasmania also ran with sustained high renewable shares throughout the week, frequently in the 85–92% range, underpinned by hydro output regularly exceeding 1,000–1,700 MW and supplemented by wind.
These high-renewable periods were consistently associated with price volatility rather than uniformly low prices — Tasmania's morning of 16 August saw prices leap from $11.06/MWh to $88.24/MWh in just 20 minutes despite 85.3% renewable penetration, illustrating how rapid shifts in hydro dispatch and demand ramp can still drive sharp price movement even in a high-renewable system. Negative pricing events across SA1, VIC1, TAS1, QLD1 and NSW1 through the week were generally linked to strong wind and solar output coinciding with low overnight demand, alongside continued coal and hydro baseload generation.
The dominant operational story of the week was the repeated binding of the T_BLINK_TV_NGZ constraint in TAS1, recorded at an identical $8.352 million shadow price across at least eight separate occasions between 10 and 16 August. This persistent, extreme-value constraint points to a sustained transmission or network limitation in Tasmania that market participants should continue to monitor, even though it did not translate into extreme regional spot prices — TAS1 prices during these events generally stayed within the $30–125/MWh range.
A separate high-value constraint (NSA_Q_GSTONE34_250) bound in SA1 twice during the week, reaching $23,108/MWh on 12 August and $1,371/MWh on 11 August. A NEM-wide constraint (F_T++NIL_MRWF_TG_R6) also registered a $244/MWh shadow price, reflecting periodic transmission bottlenecks limiting dispatch flexibility.
FCAS pricing was subdued for the week, with all contingency and regulation services trading well below historical stress levels. RAISEREG averaged $3.53/MWh and LOWERREG $1.99/MWh — the two highest-cost services — while contingency raise and lower services (6-second, 60-second and 5-minute) all averaged under $0.20/MWh. No material FCAS price spikes were observed this week.
East coast gas hub prices firmed modestly through the week. STTM Brisbane led the pack, rising from $11.00/GJ on 12 August to $11.69/GJ on 14 August before easing to $11.38/GJ by 16 August. STTM Sydney tracked a narrower band between $10.46/GJ and $11.10/GJ, while STTM Adelaide moved from $10.20/GJ to $11.09/GJ before settling at $10.61/GJ. DWGM Victoria remained the most stable of the hubs, holding in a tight $10.20–10.35/GJ range across the week.
Large-scale Generation Certificates (LGCs) continued their steady climb, closing the week ending 14 August at $8.50 — up from $8.00 the prior week and well above the $5.05 low recorded in mid-July. This marks a sustained upward run over the past five weeks, with LGC prices now back at levels last seen in late June.
With the T_BLINK_TV_NGZ constraint binding so persistently through the reporting week, continued monitoring of Tasmanian network conditions is warranted heading into the week of 17 August, particularly for participants with exposure to TAS1 pricing or interconnector flows. WA1 is likely to remain the highest average-priced region nationally, and further isolated price spikes in the WEM should not be ruled out given the pattern of recurring moderate spikes observed this week. On the east coast, continued strong renewable output combined with overnight demand troughs points to further negative pricing episodes in SA1, VIC1 and TAS1, while daytime demand ramps in QLD1 and NSW1 should keep peak-period pricing firm. Gas hub prices and LGCs both trended upward this week — a pattern worth watching as we move further into the cooler months.
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