Snowy Hydro 2.0: Is it Worth the Investment?

In this article, we examine the economics of Snowy Hydro's pumped hydro storage project, which is likely to be further delayed and come at a higher cost than originally anticipated.

Despite the recent capex projections increase, the economic value and business case for Snowy Hydro remain solid. We estimate that at least AUD 533 million in arbitrage or storage services profit margin must be made every year for the project to be "bankable."

The breakeven margin or levelised cost for every unit of electrical power produced from discharge and supplied into the local power grid throughout the system's assumed economic lifetime is estimated to be AUD 47 per MWh.

In context of the #fossilfuel based alternatives the local grid has to sourcing peaking and dispatchable power generation, the economic value and business case for Snowy Hydro remain solid, even with the recent capex projections increase.

Snowy Hydro in context

Snowy Hydro Limited 's #pumpedhydrostorage project is likely to be further delayed and come a cost higher than originally anticipated.

As Andrew Blakers AO calls out in his recent article on the topic, "#Australia’s renewable energy transformation will require a huge amount of energy storage – and the "Snowy Hydro 2.0" extension is an important part of the mix."

Snowy 2.0 will provide an additional 2,000 megawatts of dispatchable, on-demand generating capacity and approximately 350,000 megawatt hours of large-scale storage to the National Electricity Market (NEM). To provide context, the project's 2GW #zerocarbon output capacity compares to a total of 17.7GW in wind and solar currently installed and operating across the grid.

And once fully charged, it would take 175 hours to be fully discharged at maximum output capacity. This means that the #longdurationstorage system is likely to be cycle at most once per week throughout its operating life.

So, let's have a look at the likely breakeven margin or cost per MWh produced from discharge and supplied by this important #energystorage project into the Australian east coast's power grid once it becomes operational.

Economic analysis and levelised cost of storage

Despite being arguably a long term asset let's assume those immobilising capital in it want to see their money back within a 30 years economic investment horizon from start of operations, and seek a pre-tax (and pre-subsidy) real return of 6% pa.

For those who argue the infrastructure is going to last much longer than that, let's assume at the end of that period, the project assets still hold some 30% of the upfront formed asset value.

These two parameters translate the project's most recent estimated initial investment of AUD 6 billion into an annual capital recovery requirement of AUD 417 million per year. Add to that an allowance for fixed O&M costs and sustaining capital expenditures of 2% of the initial asset value, or AUD 120 million per year.

That means that, independent of the cost incurred in procuring power to time shift through the PHES system, at least ~AUD 537 million in arbitrage or storage services profit margin must be made every year for the project to be "bankable".

Now, let's assume that 90% of system's 350 GWh in raw storage capacity can be effectively discharged, its net round-trip efficiency is 70% and the system is utilised to a rate of 1 full charge/discharge cycle per week, or 52 cycles per year.

These assumptions translate to the system adding a load of 16,380 GWh per year to the local grid as it recharges to the assumed utilisation. Given the unavoidable losses involved with this?#storagetechnology, only 11,466 GWh of that becomes supply back into the grid as the system discharges. It is noteworthy that this would translate to the project increasing by 4,914 GWh/ year the net electricity load met by the NEM, a 2.3% increase!

As summarised in the table below (and GoogleSheet) all that boils down to AUD 47 per MWh the breakeven margin or cost for every unit of electrical power produced from discharge and supplied into the local?#powergrid?throughout the system's assumed economic lifetime.

This measure means that if the system is recharged at an average power purchase cost of AUD 60 per MWh to offtake and use in recharges, it must sell the MWh output it can achieve from that at at least AUD 133 per MWh effectively supplied back into the grid.

It is important to note that if an lower of number of charge/discharge cycles per year is achievable, the levelised cost of time shifting energy through the system goes up materially.

For example, if only 26 cycles are achieved every year (i.e. one cycle every two weeks), the break even margin goes up to AUD 94 per MWh, and the breakeven selling price goes up to AUD 179 per MWh. See table below for key sensitivity analysis.

Putting it in context, it looks like a good deal still

For context, a cost of AUD 133 per MWh of power discharged into the #powergrid is less than the dispatch weighted average selling price achieved by peaking open cycle gas turbine generators in the NEM in the past 12 months of AUD 386 per MWh.

This figure is also equivalent to the marginal cost of output of a peaking generator burning?#naturalgas?at a thermal efficiency of ~35% and a gas fuel cost of ~AUD 12 per GJ. This breakeven opportunity cost of gas figure is less than the average gas price of ~AUD15/GJ seen last year but above the spot gas prices seen in the second half of 2010's.

All in all, this tells me that even despite the recent CAPEX projections increase, the economic value and business case for Snowy Hydro remains solid as long as the existing and new peaking gas generators operate and seek to recover an spark spread in line with an opportunity cost of gas as high as that seen in the past years's peak values.

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