There has been talk for years about the potential introduction into the National Electricity Market of a “capacity market”, with significant pushback from the industry over the potential for a capacity market to prolong the life of coal and gas and slow decarbonisation of the grid.
On Friday last week (9 December), the Federal government announced the Capacity Investment Scheme (CIS). The CIS will only be available to zero-emission technology, which realistically means battery storage in the short term and pumped hydro and potentially hydrogen turbines in the medium to longer term.
With battery CaPex costs having risen sharply by ~30% over the past 12 months, financing storage projects on a merchant-exposed basis have been challenging. Those projects that have been getting financed recently, for the most part, have offtakes that provide a stable revenue stream. Additionally, they have mostly been developed by vertically integrated generators hedging their load exposure risk. The CIS, along with the current NSW LTESA Tender process, is a welcome addition in assisting projects to get to market more quickly.
The brief detail released on the CIS states that there will be a “floor” payment where the government guarantees a minimum return. Our Chart of the week considers the value of that floor requirement for an 8-hour battery asset.
When analysing, the outcome will be different for each asset and will also depend on the financing structure and how much debt the project can bring on, amongst other things. Our preliminary analysis (based on large batteries with more than 200MW capacity and a duration of 8 hours) suggests that the required floor price to deliver an 11.9% equity return ranges from ~$57,000/MWh to ~$80,000/MWh installed p.a. Additionally, the level of support that is then required to assist these projects meeting those minimum hurdle rates ranges from ~$15,000/MWh to ~$45,000/MWh installed p.a (around 27% – 57% of total net revenue required). On a $/MWh traded basis, this equates to ~$86/MWh to $253/MWh, which, at the low end, is starting to get reasonably close to the support currently being provided to renewable generation from LGCs which are currently trading at ~$65 and are still expected to be ~$40 in 2026. This difference in the range of support required is driven by changes in the Debt to Equity ratio (from 20/80 to 70/30 and the interest rate). For our chart we could not include all the permutations and have focused on the opportunity for higher Debt to Equity ratio projects (70% debt and 30% equity) that may be able to obtain this type of leverage where there is a floor-based government-guaranteed contract.
The returns required in the scenarios above do not include the value of any shock events, which is an unrealistic assumption as we know that these events are going to continue to occur (it is understood that the Hornsdale battery made ~$10.7M over seven days in November this year in the FCAS markets). We cannot say precisely when these low probability/high impact events may occur, but they continue to happen regularly in the market. So there should be some value attributed to that. This is the crux of the issue that the CIS can solve; it provides revenue certainty so that private capital can be deployed on a reduced-risk basis, with the floor price only being payable when these high-impact events don’t occur. The value of these contingency events drives down the support required in the contingency case from ~$60/MWh to just over $10/MWh.
We modelled a number of sensitivities for an 8-hour battery, and three of them are shown in the chart below. The assumptions they use are cumulative and assume the following:
- The high Debt to Equity (High D/E) case: the project could obtain 70% debt into the project at 5.5% (definitely optimistic!)
- The scenario with revenue from selling Cap contracts and FFR also includes 4.7% of total revenues coming from the new FFR market and selling cap contracts for 15% of the storage capacity at $15 (by selling only 15% of capacity, the 8-hour asset could cover a 24-hour period of price shocks if the storage asset was only at a 50% state of charge at the time the event occurred. This is the largest period that would have needed to have been covered in FY21, excluding the June madness, where prices were above $300 for over four days straight!)
- The scenario with contingency events included assumes that 50% of the storage asset could respond to price spikes in energy and only 15% of capacity for FCAS price spikes and that these events would occur approximately every four years (the first occurring in year one) based on high-priced events that have occurred between 2018 and 2021. Additionally, it assumes that equity reduces the returns it would require from 12% down to 9%.
What we see in the chart below is that in the contingency case (with the reduced equity returns), the actual final support required after the value of the contingency events is factored in is only ~3.7% of total revenues (rather than 20.8%).
Every storage asset is different, and the objective and manner in which they are contracted and traded are different. As more schemes are developed by states and federal government to incentivise firming capacity in the market, it will be key to evaluate and understand the value of future contingency events in the market to ensure that participation in these programs can be maximised by not underestimating the value of low probability/high impact events in the NEM.
For more information on our storage revenue forecasting services which now includes a contingency forecasting option and our energy price forecasting services, please contact us at firstname.lastname@example.org.