Are you assuming these batteries, EVs, etc are not doing anything with the power they "used up"?
One is to replace other fuel (gasoline, which is still more expensive) in transportation, the other is to shift the load, averaging out the high and low pricing. If you consider that bad I don't know what is good.
What they did is good, just expensive.
Batteries impose a round-trip cost on the process, so I don't expect consumers are going to benefit by large scale commercial storage. It's a way to facilitate increased levels of VRE where otherwise, the market wouldn't allow it to make sense because they eat each other's lunch. A developer can siphon off some of their output during low demand/low value periods and sell it into the market when demand spikes and prices are high.
Hornsdale has made a ton of money for its developer by doing FCAS and arbitrage even though its actual output is quite low. As you note, in a market, a storage medium has the ability to buy cheap and sell high, even if its overall contribution is minimal and the real value (which it is also compensated for) is improving stability with a high penetration of wind/solar.
IIRC, in the case of Hornsdale, the developer also owns the adjacent wind farm, so they are making money from both sides of this.
Hornsdale has ultimately cost (AUD) $172 million for 150MW/194MWh. That's $1.15 million per MW, roughly the same price as an average onshore wind turbine. The cycle limit of course is where the issue arises. The unit spends significant time charging and its discharge periods are short due to its capacity.
The long-term (not FCAS) storage side of the battery can discharge 30MW for 3 hours (they have the battery operation partitioned) and it does exactly what we just discussed, it buys power when it is cheap and sells it back to the grid when demand is high, making the developer money.
If we assume that it is able to cycle this side of the battery at full nameplate for three hours every day (90,000kWh), that's 32,850,000kWh/year; 32.8GWh. Assuming a 10 year lifespan, to pay off half of our storage medium (assuming the other half is paid off by FCAS) we'd need to receive an average per kWh rate of $0.26. However, we have to consider the price it buys the power it charges for on top of that. So, assuming it buys power at $0.04 for example, it would need to then sell it at $0.30/kWh.
Then we have the other half of the battery, which can discharge up to 104MWh for less than an hour at 110MW to improve stability. Assuming a 45 minute discharge cycle per 24hrs, that's 82.5MWh per day, 30,112,000kWh/year. It faces the same problem, it needs to buy power when demand is low in order to be able to discharge during periods of instability, assuming it doesn't have the luxury of buying at $0.04/kWh, let's bump that up to $0.06/kWh. Since we aren't full cycling and our annual output is lower, our base rate in this role is $0.29/kWh. Adjusted to include charging, it is $0.35/kWh.
So the overall operating rate for the battery using the above scenario is ~$0.32/kWh in order to pay for itself within a 10 year lifespan or amortization period. That's certainly no deal for the ratepayer. So, is that cheaper than a gas plant? It will depend on the state of the market. Given the very short duration of storage provided by the battery, gas will still be necessary for longer low VRE output periods. And it will be able to command an even higher price once storage is depleted.
As I noted above, what I expect we'll see is more paired storage owned by the same developer that has the VRE resources. They can siphon off their own output when market price is in the toilet, demand is low and output is high, and then sell from their storage when demand spikes and the price goes up. They are basically just taking advantage of the same position the gas plant operators are in, which allows them to install more VRE capacity than would otherwise be profitable.
