Federal ministers have detailed a new gas reservation policy requiring exporters to allocate 20% of spot production to the domestic market from January 2025. The mandate exempts existing export contracts but aims to mitigate a forecast east coast supply deficit by mid-2028. This direct market intervention addresses long-term supply security concerns, setting a new baseline for gas producers and large industrial users planning for the decade ahead.
The policy arrives as new demand forecasts reveal the scale of the grid's challenge. AGL Energy projects a seven-fold surge in electricity demand from AI data centres, a figure that significantly exceeds official AEMO projections. The gentailer plans to deploy large-scale batteries to improve the operational efficiency and financial returns of its coal-fired generators, using storage to capture value from this unprecedented demand growth.
Meanwhile, behind-the-meter storage is already delivering significant grid impact. The federal Cheaper Home Batteries Program has installed 10.7 GWh of storage across 380,712 homes since its launch last year, according to Energy Minister Chris Bowen. NSW Energy Minister Penny Sharpe described this uptake as a "turning point" for reliability, citing the contribution of home storage during the state's recent "baking hot summer." This demonstrates a direct link between federal subsidies and state-level system resilience.
Utility-scale storage is also setting new benchmarks for performance and capability. Queensland became the first NEM state to discharge over 100 GWh from battery storage in a month, a milestone for grid-scale energy shifting. On the technology front, Sungrow successfully demonstrated a 19-second black start using its grid-forming battery system at a 30 MW test facility. This proves the technology's ability to restore power to an inactive grid without external supply, a critical service for a transitioning system.
Despite this momentum in storage and demand, a fundamental market disconnect persists. Depressed wholesale electricity prices are failing to provide a viable investment signal for new renewable generation. NEM spot prices averaged $48.83/MWh, down 4.3% week-on-week, reinforcing the "spot mirage" that masks the need for new capacity. This pricing environment undermines the business case for new wind and solar projects, creating a long-term risk to grid stability and decarbonisation targets.
International markets offer a cautionary tale of this imbalance. In Greece, persistent negative prices and high curtailment are pushing small-scale solar asset owners toward bankruptcy due to insufficient storage and demand-side flexibility. France also recorded unprecedented levels of negative pricing in April as surging solar generation collided with inflexible nuclear output. These examples highlight the financial distress that occurs when renewable deployment outpaces market and infrastructure reform, a key risk for the NEM to manage.
This focus on market design and infrastructure investment will dominate the regulatory agenda. The AER is progressing its next five-year revenue determinations for transmission networks including Transgrid, ElectraNet and Powerlink, which will govern billions in grid investment. Stakeholders have several opportunities to shape market rules in the coming weeks, with AEMO seeking input on procedures for its Independent Expert Council and real-time data provision.