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      Generation & Storage, Hydrogen — 5 mins read

      Batteries vs hydrogen for energy storage in the NEM

      By Joel Gilmore, Tim Nelson and Tahlia Nolan

      Australia has committed to reducing its greenhouse gas emissions. One of the ways in which this commitment is being realised is through a shift towards variable renewable energy (VRE) within Australia’s National Electricity Market (NEM). Given the unpredictability of solar and wind resources, consideration must be given to technologies which can address short-term and long-term mismatches between resource availability and demand.

      In this article, we have undertaken time sequential simulations of the NEM with a custom-built model to find the optimal firming technology plant mix for a zero emissions grid. Our conclusion is that some form of fuel-based technology (most likely hydrogen) will probably be required, even if that fuel is very expensive. This has important implications for Australian energy policy, and where investment in emerging technologies should be focused.

      Most existing studies of high penetration VRE electricity systems have focused on short-term mismatches between resource availability and demand which are well served by deployment of batteries and pumped hydro. Much less has been quantified about the need to deal with infrequent ‘energy droughts’ where there is a prolonged shortfall of solar and wind resources but continued use of electricity. 

      Longer duration ‘energy droughts’ will occur in all electricity systems, so it is necessary to consider how electricity systems will maintain system reliability and security when pumped hydro and battery storage resources are depleted and there is ongoing scarcity of instantaneous solar and wind resources.

      While a simulation with no fuel-based technologies will “solve” (i.e., it is theoretically possible to meet demand using only battery and pumped hydro storage), we find costs are lower if a modest amount of zero-emission peaking units are included. Critically, even if fuel costs are very high, ‘green gas’ or ‘green hydrogen’ may be economic for providing very infrequently utilised capacity to address low probability but high consequence energy drought events. This holds even if future energy storage costs are even lower than current projections.

      In particular, we find fuel-based technologies are economical over energy storage to manage comparatively rare but high impact periods of low renewable supply, which might occur only 1 in 5 or 1 in 10 years. Batteries or pumped hydro assets that are rarely used are much more expensive than deploying comparatively low capital cost peaking units that can deliver energy on demand at high value times. These dispatchable capacity options include current thermal technologies such as Open Cycle Gas Turbines that may utilise growing volumes of alternative fuels in the future such as hydrogen or biodiesel. 

      To be clear, energy storage is also critical for an efficient and cost-effective grid. Energy storage systems provide significant value across the year, and in our model will charge off both renewables and the zero emissions peaking units. This helps maximise the value of those peaking units. This is not just theoretical; batteries in the NEM have already been observed charging at prices above A$10,000/MWh in order to produce later at periods approaching A$15,000/MWh.

      Three significant policy implications flow from our analysis: 

      • Scaling investment in zero emissions thermal plant technology will help reduce future costs, and increase resilience. Commercially available turbines that can run on 100% hydrogen may be very valuable in the future
      • Uptake of zero emissions fuels should be incentivised more broadly, such as through introducing mechanism to increase the production of ‘clean fuels’ within existing networks
      • The future market requires generation that can turn on and off quickly. Hydro, gas and batteries fit this description, not coal-fired power stations. Asking consumers to pay again for these power stations to ‘stay in the market’ doesn’t seem fair or equitable. Correctly valuing capacity payments for firming assets with very different operational capabilities will be increasingly difficult. In contrast, the NEM’s existing energy-only market already deliver strong signals and market design should focus on incremental changes that support investment rather than introducing complex and unnecessary reforms.

      In conclusion, a diverse mix of firming technologies will be required. Governments need to scale investment in zero emissions (renewably powered) technology by working with the domestic industry and OEMs to increase the deployment of very high penetration green hydrogen or biogas turbines. The introduction of Green Gas Targets modelled on Australia’s existing Renewable Energy Target to drive investment in hydrogen production should also be considered.

      This article is a summary of a scientific paper that has completed the peer-review process and been accepted for publication in The Energy Journal. You can view the full text here.

      Dr Joel Gilmore, General Manager Energy Policy & Planning, Iberdrola Australia

      Energy Monthly

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      March 25, 2024 | Sheraton Grand Sydney Hyde Park

      Australian Domestic Gas Outlook 2024

      June 11, 2024 | Melbourne Convention and Exhibition Centre

      Australian Energy Week 2024

      New call-to-action