Distributed storage

The Smart Grid, Smart City Distributed Storage trial used a 5kW/10kWh zinc-bromide ‘flow’ battery technology with a remotely controllable battery management system including a grid-tie inverter. At the time of the field trial, the zinc-bromide ‘flow’ battery was new on the market and the only approved grid-connected storage device available (excluding older lead acid technologies). The zinc- bromide ‘flow’ battery has a full depth of charge advantage over lead acid batteries which means a smaller unit (kW) could be deployed.

Grid battery storage was not successfully implemented in the field trials due to a number of challenges which are discussed in the Distributed Generation and Distributed Storage (DGDS) Technical Compendium.

As a result, the specific storage technology used in the trial was not used for the national business case assessment. Instead, lead acid technology was used in the modelling, because it has been demonstrated in an Australian context and because greater operational and financial data was available. Distributed storage has the potential to contribute to the management of growth in system peak demand and has implications for future electricity bill increases. Modelling showed that despite anticipated price reductions in distributed storage devices, without changes to retail electricity pricing structures (i.e. under BAU) there will be no deployment of storage through to 2034 in Australia. Modelling clearly shows that the existing tariff structures effectively discourage the uptake of battery storage technologies.

For commercial customers under the BAU case, price signals encourage investment in relatively large rooftop solar PV and CHP systems. The systems will likely export to the grid during times of low demand, incentivised by a volume based inclining block tariff. In contrast to residential customers, the size of the solar PV systems deployed was not significantly different under either a BAU or smart grid case. This suggests that solar PV for commercial customers is likely to be a financially viable solution in the future regardless of scenario, given the anticipated further reduction in solar PV panel costs.

In summary, under the smart grid case, dynamic pricing (network capacity charge in combination with a retail critical peak price) drives the deployment of smaller rooftop solar PV systems (around 3 GW less) and CHP (around 1.8 GW less) in the NEM by 2034 compared to BAU. This however, is balanced by the deployment of around 3.5 GW of storage capacity. Under both BAU and smart grid cases, there is growing adoption of solar PV generation by both residential and commercial electricity consumers. The field trial and modelling showed that the

effectiveness of rooftop solar PV systems in reducing summer peak demand is limited, mainly due to misalignment of the timing of rooftop solar PV system output and peak network demand. Advanced

modelling of high PV penetration scenarios found that PV reduced feeder peak load on average by 3 per cent. It was also found that the hottest days were not necessarily the sunniest, with later afternoon clouds reducing the amount of available solar radiation on some days.

In the case of the field trial for small wind turbines, generation profiles were highly variable and

intermittent and did not necessarily match customer energy usage or network peak load profiles. The generation profiles had minimal impact on reducing summer peak demand in the Gundy trial area on the focus days studied. The trials also indicated that the customer and network value of this technology is on average likely to be low and generally less than a comparably sized PV system.

While the fuel cell technology trialled had some capability to reduce network peak load, the more efficient operating mode was ‘continuous operation’ (constant output at the rated capacity of 1.5kW) reducing network load at all times. The results from the trial indicated that the potential customer value of this technology was highest for customers with a higher than average electricity consumption and the ability to better utilise the heat which is generated as a by-product.

Modelling suggested that the introduction of dynamic tariffs (critical peak pricing) in conjunction with network capacity tariffs (i.e. the smart grid case) would give rise to a different configuration of combined distributed generation and storage devices at customer premises.

The Smart Grid, Smart City trials indicated that there is potential for distributed storage to export into the grid during peak events and that export during these times could provide a cost effective alternative to centralised generation from peaking plants. Currently, exports during peak events from distributed generation or storage devices are not efficiently valued. At present, any export during these events is valued at the feed-in-tariff rate, based on the weighted average cost of wholesale electricity during solar PV export hours, rather than the higher value of generation at peak times.

Notwithstanding, there are no existing regulatory barriers to retailers offering a dynamic feed-in-tariff which increases during peak events to better reflect retailer costs. This does not occur at present and was not considered in the modelling exercise. However, it is foreseeable that once distributed storage

technology becomes more broadly available, retailers would implement such a tariff which would further incentivise distributed storage uptake beyond what has been modelled.

Even with such a dynamic feed in tariff, there remain barriers for network businesses to provide price signals to customers as to value of export from distributed storage during network peak events. Such a price signal could potentially take the form of a one off incentive payment or network rebate during events. This would essentially function as a demand response mechanism (similar to the dynamic peak rebate product trialled), but would reward customers for not just offsetting their own demand but for achieving negative net demand in peak times.