Current numbness are lower but in 2022 you could use LFP for ~5,000 discharge cycles and pay ~480$/kWh of capacity or ~9.6 c/kWh. Inverters etc last longer than the batteries themselves so you can amortize those costs across multiple generations of batteries, therefore it’s not that to calculate upfront costs / number of discharge cycles. https://www.nrel.gov/docs/fy23osti/85332.pdf
Still roughly 2c/kWh * 105% + 9.6 c/kWh * 50% ~= 6.9c/kWh averaged over a day.
Currently batteries are discharged at peak demand, but the underlying economics scales just fine even if you double the number of solar panels for redundancy and aren’t being paid a premium. Further at scale demand that shifted to cheaper nighttime rates will instead shift to cheaper daytime rates.
For reference on new build, at the UK government's most recently completed CfD auction (which happened in September), the solar PV bids accepted were at £47/MWh, CPI indexed and specified in 2012 prices: https://www.gov.uk/government/publications/contracts-for-dif...
NYC is 40.7’ North, Toronto Canada is North 43.7’, London is 51.5’ North and that’s the southern part of the UK.
You can also look at Spain - the CfDs aren't really comparable since the way CfDs are used there is different but LCOE is probably in the 40s-50s EUR/MWh for new build solar PV. But there are now meaningful curtailment issues in some places due to grid capacity there so developers will probably be working to higher numbers.
One issue for significantly higher UK solar production is they use more electricity in the winter. January 2023 was 26 TWh where July 2022 was only 20 TWh which is the opposite of solar’s peaks.
They can import from France, but France also has higher demand in the winter: https://www.statista.com/statistics/1107089/electricity-cons...
It’s only when you’re far enough south to see significant summer AC demand that it flips.
We have to keep in mind that 6.9 isn’t yet the end user rate after grid fees, but still.
There is also a ton of potential in demand shaping by offering hourly prices to customers.
The place where batteries fail is long-term, seasonal storage. The price per charge is still low, but an asset that takes 5000 years to amortise (one charge cycle per year) is not a competitive investment.
So we will need other approaches here, where the substance that stores the energy is cheap and the cost is shifted onto the energy transforming device (this is e-fuels/ ammonia/ hydrogen)
So rather than having a singe battery doing nothing for 364 days a year and getting used one day you have a battery bank which gets discharged slightly more 1 day a year and recovers that deficit over some time period.
For redundancy reasons you want excess generation capacity should something happen which would most of the time allow for a full charge soon afterwards.
PS: individual wind locations also tend to get more power on specific time of the year which can offset seasonal issues.
Suppose a normal discharge cycle costs 10c/kWh and a very deep discharge costs 100c/kWh to access that last 10%. That means there are energy reserves unacceptably expensive for normal operations, but it also means simply operating batteries efficiently automatically creates reserve capacity which is the entire point of dedicated seasonal storage.
Put another way if you design a 1TWh battery for daily use it’s going to have a 0.1TWh reserve capacity just sitting there.
This isn’t a lot of power across a full season, but it address seasonal storage in terms of short term abnormal peaks like heatwaves.
PS: Proponents of seasonal storage argue for seasonal deficits in production rather than short term gaps. However, the daily variability of renewable production promotes significant excess generation capacity.
What’s left for “seasonal storage” is to cover gaps in production from extreme outlier events using surplus production. That is useful, but also largely covered by battery power as I just covered.
Granted if someone comes up with cheap enough seasonal storage it might have a place, but that’s a possibility not a guarantee.
Well-provisioned solar farms can synthesize and tank their own ammonia during periods of excess production, and sell excess (over what local tankage holds) on the open market.
Someone in Iran told me these are about 3500 years old
So, there is a long term need, in order to reach a goal of 100% carbon free electricity (generally set for about 2035) for more on-demand resources (including responsive demand), but it is not the most pressing concern right now. And even when it is, it'll account for a small fraction of the total, like 10% or so.
(Luckily, batteries are gettting rolled out already because they have positive economic value in various niches, like in cars, frequency response, avoiding congestion and network upgrades so the ramp up is looking good)
The economically viable mass storage options (i.e pumped storage) are basically all deployed. Batteries are getting there but they still need some shenanigans in the ancillary market where they get paid for not running for complex reasons to make the economics in most instances. As the shenanigans price out nat gas in those markets it will be interesting to see how offer strategies of nat gas change to recoup the lost economic viability and if that makes batteries less profitable.