December 2025 & January 2026 – Review of Market Events
By Aaron Bool
Wholesale pricing outcomes through December were generally lower than those observed in recent years, reflecting favourable supply conditions and elevated renewable availability. Strong wind and large-scale solar output, supported by increasing battery participation, continued to displace higher-cost thermal generation during daylight and shoulder periods, placing downward pressure on prices across most regions.
This broader pricing environment was reinforced by the release of Australian Energy Market Operator’s Quarterly Energy Dynamics report for Q4 2025, which highlighted a continued structural shift in the generation mix. The quarter marked the first time that renewables supplied more than half of total NEM generation, supported by strong rooftop solar output and a growing contribution from grid-scale batteries. Despite underlying demand reaching new highs during the quarter, increased renewable and storage availability reduced reliance on coal and gas generation, both of which fell to record low output levels. Emissions outcomes for the quarter were also among the lowest recorded, reflecting the changing supply profile across the market.
Demand conditions during December were highly variable. On Christmas Day, record low operational demand was observed in South Australia and Victoria, driven by reduced industrial and commercial activity combined with strong rooftop and utility-scale solar output. In contrast, late-December heat events lifted demand in New South Wales, with market demand exceeding 12,000 MW during mid-afternoon trading intervals. These opposing outcomes again highlighted the widening gap between minimum and maximum demand during summer.
January 2026 was dominated by sustained heat across multiple regions, resulting in higher and more persistent demand outcomes. NEM-wide demand exceeded 33,500 MW during early January, while New South Wales experienced repeated periods of elevated demand during hot weather events. Victoria recorded a new all-time operational demand record on 27 January, while extreme heat in South Australia around Australia Day led to prolonged periods of elevated spot prices near the Market Price Cap. These conditions underscored the market’s sensitivity to extreme weather and the importance of dispatchable capacity during peak demand periods.
A number of operational events also influenced market outcomes over the two-month period. In early December, the Wellington North Solar Farm was taken offline following a nearby grassfire, highlighting the growing exposure of renewable assets to bushfire risk during hot and dry conditions. During January, unplanned outages at large thermal units, including Callide C units in Queensland, contributed to short-term volatility in spot and ancillary service markets. Ongoing network constraints, particularly across key New South Wales transmission corridors, continued to influence regional energy flows and pricing outcomes.
Battery operations remained a prominent feature of system performance. Large-scale batteries increasingly provided both energy and system security services during periods of high demand, helping to manage short-term imbalances. At the same time, January’s heat events again demonstrated the challenges of maintaining system balance during prolonged periods of elevated demand, reduced renewable output and constrained network conditions.
Several structural and policy developments progressed over the reporting period. In December, AEMO formally requested that Notice of Closure requirements for exiting generation plant be extended in certain circumstances, reflecting the need for greater visibility and lead time as ageing coal-fired generators approach retirement. Against this backdrop, confirmation of an extension to the operation of Eraring Power Station was a particularly important development for New South Wales. The decision reflects growing recognition that delays to transmission projects and slower delivery of replacement generation and firming capacity have increased near-term reliability risks, with Eraring continuing to play a critical role during peak demand periods.
Private sector investment activity over the period reinforced similar themes. Following the $6.5 billion acquisition of Alinta Energy by Sembcorp, the new owner confirmed its commitment to maintaining the operation of Loy Yang B Power Station, positioning the asset as a key contributor to system reliability while supporting accelerated investment in renewables, storage and firming capacity.
Forward electricity markets softened further over the reporting period, with CAL 26 contracts declining across all mainland regions. In New South Wales, CAL 26 pricing fell from $109.51/MWh at the start of December to $90.88/MWh by the end of January. Queensland followed a similar trend, easing from $90.90/MWh to $75.84/MWh, while Victoria declined from $75.75/MWh to $65.85/MWh. South Australia also softened, with CAL 26 pricing moving from $91.62/MWh to $87.31/MWh. These movements occurred alongside continued weakness in longer-dated contracts, with CAL 27 and CAL 28 also trending lower through late 2025 and early 2026.
Looking ahead, near-term market conditions are expected to remain sensitive to weather-driven demand, generator availability and network constraints through the remainder of the summer period. While forward pricing continues to point to improving supply conditions and a lower long-term risk premium, short-term volatility is likely to persist during periods of extreme heat and unplanned outages. In this environment, close monitoring of operational conditions and maintaining flexibility in procurement and risk management approaches will remain important in the near term.
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