TL&DR Summary: they can. But the economics of energy storage depend on the application, and no energy storage option makes cheap kWh unless it is used to deliver enough kWh. Long term storage must have an ultra-low capital cost to be affordable, because otherwise its cost is not distributed over a large enough number of kWh.
There’s a lot of misunderstanding around batteries. Myths abound. The myths arise because a kernel of truth is misunderstood and then turned into popcorn by the FUD spreaders (fear, uncertainty and doubt) and nirvana fallacy pushers.
One popular myth, or misunderstanding, is that batteries can’t store more than about four hours worth of electricity.
A lithium ion battery can store energy for months. Self-discharge rates in LFP cells are on the order of 1-5% per month. So no, it’s not that if you store energy for longer in a battery, it will drain away or disappear.
However, it is quite a different matter to say that you could afford to build a battery storage system which stored a month’s worth of electricity!
The economics of energy storage are pretty simple, but you need to understand them to know why people target a particular storage duration- and why the problem of long duration or worst of all, seasonal energy storage, has so many people scratching their heads and looking at all sorts of weird and wonderful things to solve it.
Numbers are instructive here. So let’s take a simple example: a home energy system.
Let’s say that you buy LFP batteries and put them together into a 100 kWh pack, with a total cost of $100 USD per kWh of storage. That’s quite achievable these days, if you don’t need a pre-packaged, certified battery product “solution”- just one that is safe enough to use and reliable enough to depend on.
Large format LFP cells have a guaranteed cycle life on the order of 6000 cycles, meaning that you can charge and discharge these batteries to (near) their full capacity about 6000 times before they drop to 80% of their original capacity. 6000 daily cycles would take 16.4 years.
All lithium ion batteries also start degrading from the first time they’re charged. So-called “calendar life” results in a degradation of about 1% per year, even when they’re just stored, not cycled at all. It would therefore take 20 years for these batteries to degrade to 80% of original capacity even if they were never cycled. If the batteries are stored at 90% state of charge (SOC), degradation can be much faster-up to 3% per year, or 6.7 years to drop to 80% of original capacity. So in a sense, the cycle life of Li ion batteries is to some degree a “use it or lose it” proposition.
But to make the math simple, let’s make the following assumptions:
100 kWh of battery storage
90% state of charge per cycle, i.e. taking the cells from 100% to 10% SOC each cycle
One full cycle per day
6000 cycles guaranteed life. And calendar degradation of a little more than 1% per year, so that the battery will still need replacement in 16.4 years
$100/kWh initial capital cost.
90% round trip efficiency, i.e. if you feed 10 kWh of electricity to the charging circuits, you get 9 kWh back out again at the input of your inverter.
The battery would therefore return 100 kWh x 6000 cycles x 0.9 SOC x 0.9 efficiency = 486,000 kWh, delivered over 16.4 years of operation.
The raw capital cost of the battery would be $100/kWh x 100 kWh = $10,000. Of course we pay that on day 1.
Ignoring interest rates, the simple cost of storage per kWh returned is therefore $10,000/486,000 kWh = $0.02/kWh, plus the cost of electricity fed to the battery (divided by 0.9, because we must feed 10 kWh to get 9 back due to the efficiency).
Add in an interest rate, because we don’t get capital for free, and the cost per kWh goes up, because the kWh are delivered in the future, whereas the capital must be paid for on day 1.
What happens if we chose to do a cycle every 2 days instead?
Nothing changes, except the number of cycles, which now drops to 3000 in 16.4 years. The battery will still need retirement due to calendar life. The simple cost per kWh simply doubles as a result, to $0.04/kWh.
What happens if we were to cycle it only once per month?
Wow- now the simple cost of capital is spread over only 16.4 x 12 = 197 cycles. The cost per returned kWh is now $0.63/kWh! Or maybe a little less, if the battery cycled so infrequently, lasts 20 rather than 16.4 years.
You can see what happens if we cycle the battery less frequently, just from this simple math! And remember- real projects need to provide a return to their investors, so our simple cost of capital calculation (ignoring discount rates, i.e. interest) underestimates the real costs per kWh. And for real projects, the revenue from production more than 20 years after the project is initiated, at the sorts of interest rates expected by lenders or investors, ends up not mattering all that much.
The same sorts of calculations can be done for every kind of energy storage scheme imaginable. And the end results are similar.
You can summarize the influence of each factor as follows:
Capital cost: the cost per stored kWh, or per potentially returned kWh in lower efficiency storage schemes, is strongly dependent on the capex of the battery. Expensive batteries can only pay back their investors if they are cycled frequently. Batteries which will get few cycles per month, or per year, because they are designed with longer discharge periods in mind, will need to either be very cheap, or to have very desperate customers willing to pay a high cost per returned kWh.
Cycles: more frequent and hence shorter cycles, reduce the cost per returned kWh, irrespective of capital cost
Cycle life: as long as cycle life is long enough to match calendar life, increasing cycle life beyond this, doesn’t matter in economic terms- though it might matter in lifecycle environmental impact terms. And money spent to extend cycle life, generates diminishing returns. Note that while sealed batteries of all kinds have both cycle and calendar life, other schemes such as flow batteries, pumped hydro, compressed air storage etc., all have other things like operation and maintenance costs that vary in more complex ways with how frequently and deeply and quickly they’re cycled
Efficiency: high efficiency helps by dropping the cost per returned kWh. Low efficiency means that the cost per returned kWh increases. It’s also important to note that with Li ion batteries, which have high efficiency, there is little difference between storage capacity (the ability to absorb kWh) and returned energy capacity. However, if you have a 100 kWh battery or storage system which has return-from-storage efficiency of only 50% (which may be the case with iron-air batteries), it’s really only a 50 kWh battery. Stating its cost per stored kWh, gives a false notion of the cost of each kWh returned.
The implications for various use cases and types of storage batteries are worthy of consideration.
Solar Storage: the presence of significant solar in the supply mix, more or less guarantees one cycle per day to a grid storage system. And grid storage doesn’t care much about energy density per unit mass or volume. But what do you do to level out differences between sunny days and cloudy/rainy ones? Or between summer and winter, particularly in snowy regions? You certainly will NEVER use batteries to store excess solar kWh in summer, for use in winter- you’ll need another strategy.
Aircraft: electric aircraft would more or less be guaranteed one or more cycles per day. Their main concern therefore isn’t capital cost per kWh stored, but things more important to feasibility: energy density per unit mass and volume for instance
Ships: transoceanic ships are very sensitive to fuel/energy cost, and would initially seem like a good option to be electrified if they can be recharged with inexpensive electricity from wind and solar. However, because it takes a ship over a month to cross the Pacific at an economic travel speed, any battery used in a ship would need to be very, very low in capital cost, or each returned kWh within its calendar life will be unaffordable to the ship’s operator. However, applications like ferries are at the opposite end of the spectrum. A short distance ferry may have its battery cycled several times per day, and are therefore an obvious target for electrification
Flow Batteries: the putative benefit of flow batteries is that they allow the decoupling of power (energy produced per unit time, ie. kW) from storage of energy (i.e. kWh). A vanadium redox flow battery (VRB) is the simplest example: a flow battery stack, rather like a fuelcell but constructed differently, is used to charge and discharge the battery, and its size (and cost) is determined by the rate at which it must be able to absorb power during charging and supply power during discharging. Energy storage, in contrast, consists of paired tanks, generally plastic tanks, full of anolyte and catholyte- solutions of vanadium ions in sulphuric acid. Charging and discharging involve pumping solution from one tank to the other. While the tanks themselves are very inexpensive, the vanadium solution sadly isn’t. Enough vanadium solution to store 1 kWh currently costs over $100 at market prices for V2O5 and making reasonable assumptions for the cost of making a suitable electrolyte solution. When LFP prismatic cells can be purchased retail for $50/kWh, and with the potential for sodium ion batteries to be cheaper still in no more than a decade, VRBs therefore seem to be a technology that is dead in the water.
Iron/Air batteries: proponents such as the well funded startup Form Energy, propose to use very simple (in concept) reversible aqueous iron corrosion and plating as a method for very low cost long duration energy storage. However, the devil seems to be firmly in the details here. Very low efficiency combined with practical constraints related to the rates of charging and discharging, the stability of the battery in storage (ie. High self discharge rates) etc., mean that to be competitive, iron-air batteries would need to be very, very cheap per stored kWh to fill a niche as longer term storage media which are therefore cycled infrequently. It is not clear that they will achieve the necessary low costs at scale to find a niche.
Hydrogen: low cycle efficiency plus high capex and low energy density per unit volume, make hydrogen a structurally bad battery scheme. While the cost per stored kWh of hydrogen energy in a salt cavern might be very low, the very best case efficiency is about 37% on a cycle basis, i.e. buy 3 kWh, get 1 back. Furthermore, the capital cost per kg of hydrogen produced, is strongly sensitive to capacity factor of the electrolysis equipment. Similarly, the cost per returned kWh is strongly sensitive to the capacity factor of the equipment (fuelcell or gas turbine power plant) that is used to make electricity again from the hydrogen. Furthermore, electricity production and storage locations are not co-located, requiring bespoke new infrastructure to move hydrogen from where it’s produced to where it’s to be stored, and then on to where it will be burned again. The end result is that the notion that we will make hydrogen only from renewable electricity when it is available in excess, and then store it for use during kalt dunkeflaute conditions that might exist only a week or two per year, is just utterly an economic myth. It will never be affordable as an energy storage scheme.
Emergency Response/Dunkelflaute Power Storage
Any emergency backup power solution must meet the following criteria to be successful:
1) It must be reliable, without fail. If this condition isn’t met, the solution is worthless
2) It must have a low capex, because it will be operated infrequently and hence it will have very few kWh to spread its capex over
3) Opex (fuel cost) and efficiency are important, but secondary to capex, again because there are few kWh being consumed so total cost of fuel is small
4) It is presumed that all the strategies practical to mitigate and minimize the depth and duration of these emergencies, have already been deployed: overbuilding renewables, wider bidirectional grids, smart demand management etc., as detailed in my article about the whole subject of energy decarbonization:
https://www.linkedin.com/pulse/what-energy-solutions-paul-martin
To me, the solution that best fits this need, is stored fuels. Fossil fuels perhaps at first, and ultimately, if we are worried about the last few percent of decarbonization, biofuels.
Best of all, we have fossil fuel infrastructure which can be repurposed to meet this need. There are, for instance, existing transmission and storage infrastructure for natural gas, which are fully paid for, which have no other use in a decarbonized future, and which therefore only need to be maintained. We could, for instance, store a whole year’s worth of anaerobic digestion biogas in the existing natural gas infrastructure, using it only to supply those few applications which need fire rather than just heat, and also serving as a reservoir of energy for both emergencies and the dunkelflaute (periods of cold, dark calm when wind and solar power fall away for periods of days to a week).
These emergency generation assets would need to be low capex, because they would be used to make comparatively few kWh each year. And any asset that is used infrequently, will be very dependent on the cost of capital, i.e. the borrowing cost to pay for it. Such assets are therefore best publicly owned, because governments have the lowest borrowing cost.
If you find the topic of energy storage interesting, Rosemary Barnes’ video is worth watching:
Disclaimer: this article was written by a human, who uses generative AI only to generate images that I can’t draw myself, not to write anything. Humans, just like the AI who scrapes their content without permission, are known to make mistakes from time to time. If you find a mistake, feel free to bring it to my attention with good references and I’ll happily change the text- and my mind.
If however what you don’t like is that I’ve taken a dump on your pet idea, feel free to contact my employer, Spitfire Research, who will be happy to tell you to piss off and write your own article.