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Narratives and framing are an essential part of political story telling. Snowy 2.0, Australia’s proposed pumped hydro project, is building on the “nation building” narrative of the original Snowy 1.0, and being framed as a universal solution to wind and solar intermittency.  But does it stack up and should we care? It is obvious that more storage is useful, but at what cost?

Snowy 2.0 is rated at 2,000 MW and 350 GWh, and has the objective of supporting the uptake of intermittent renewable energy into the national grid. I wrote about this in 2017, however, Bruce Mountain recently published an article in The Conversation, arguing that the project is not cost effective based on more recent cost estimates. The original projected cost of $2.1 billion may blow out to possibly $10 billion by Bruce’s estimates. 

A pumped hydro primer 

Before looking at Snowy 2.0, it’s worth providing some context to pumped hydro storage. Nearly all global electrical storage to date has been pumped hydro storage (PHS), which makes up 97% or 183 GW of global power capacity for electrical storage. The three leading PHS countries are Japan with 28 GW, China at 32 GW, the US at 24 GW, and the European “Eurelectric region” at 35 GW. Many other electricity storage technologies are deployed globally, but apart from batteries and prospectively hydrogen, all comprise a tiny share. Batteries are much more expensive on a per-kWh basis, but can be deployed flexibly and well suited to short-term (less than 4 hour) storage. Assuming electrolysis and fuel cell costs continue to reduce, hydrogen may eventually be viable for longer-term (multi-week) electricity storage. 

Globally, PHS was historically associated with coal or nuclear baseload. In the US, the deployment of PHS was relatively slow until the 1960s, but developed in parallel with nuclear during the 1960s and 70s, and subsequently slowed in the 1980s when nuclear deployment came to a standstill. Baseload-PHS usually operates with a daily arbitrage cycle between overnight off-peak and daytime peak. The daily cycling maximises energy throughput for a given storage capacity and underpins the economic return for PHS. Furthermore, the high inertia of a long water column requires a steady and continuous electricity supply during pumping, hence the reliance on overnight baseload. 

Since the deregulation of electricity markets, the use of pumped hydro has expanded to cover a range of additional services. PHS can also be used for load following intermittent renewables, provided that continuous power is available for charging.  

In Australia, PHS charging is simply utilising whatever generation is available – whether it be coal, gas, wind or solar. In practice, PHS is more likely to be relying on overnight coal baseload and surplus overnight wind at increasing wind penetration. Since the 1980s, PHS has been superseded by gas turbines, which have a low capital cost and quick build time, and present lower risk for investors. 

Australia’s pumped hydro schemes 

Australia already has 3 PHS storage plants – Wivenhoe (CS Energy), Shoalhaven (Origin Energy) and Tumut 3 (Snowy Hydro). Wivenoe usually operates with about a 0.8 GWh pump cycle, Shoalhaven about 0.7 GWh, Tumut about 1.5 GWh. Tumut 3 capacity is 1,800 MW (after being upgraded from 1,500 MW in 2011), but only 3 of the 6 generators have pumps. These plants total about 3 GWh total storage but the theoretical capacity may be greater. Pumping power capacity of Tumut is 473 MW; Shoalhaven 240 MW; and Wivenhoe 550 MW. The proposed Snowy 2.0 is rated at 2,000 MW and a massive storage capacity of 350 GWh, although the practical storage capacity may be much less than this. To get a sense of scale, the NEM supplies about 600 GWh of energy per day. 

Interestingly, Australia’s PHS plants aren’t used that much. There was only 118 GWh and 172 GWh consumed in pumping by these plants in 2014 and 2015 respectively. Total capacity for these is about 1,391 MW giving a capacity factor of 1.0% and 1.5% respectively. Given the sunk cost, I’m not sure why these plants aren’t used more. There are several possible explanations, including price gaming, ‘gentailer’ strategic behaviour, and higher minimum arbitrage than often assumed.  

Traditionally, a low off-peak and high peak price supported PHS but price volatility is also seen as being essential with greater penetration of renewables. South Australia has a more volatile electricity market which improves the volatility economics for the proposed Energy Australia seawater scheme on the Spencer Gulf, but may not provide the certainty for a regular arbitrage cycle. The problem with relying on volatility of course, is that additional supply cannibalises its own economics. The supply-price curve is often highly elastic during peak demand periods, therefore a modest increase in supply can drive a comparatively larger decline in price. To date, there is no case outside the baseload-storage model of a large-scale electricity market driving price signals capable of incentivising investment in large-scale storage. 

What does it all mean? 

What does all this mean for the Snowy upgrade? More storage must be better for the national grid as more intermittent generation is added, but is this project economically viable?

I’m interested in why the existing PHS facilities aren’t being used more and why the proposed expansion will be better. Is the market structured for merchant storage? What scale of PHS will be required at higher penetration of intermittent renewables? Will long-term storage, including hydrogen, become more important as coal plants retire?