Energy storage: top conclusions into batteries?

Conclusions into batteries

Thunder Said Energy is a research firm focused on economic opportunities that drive the energy transition. Our top ten conclusions into batteries and energy storage are summarized below, looking across all of our research.

(1) Transportation: a revolution. Gasoline and diesel vehicles are 15-25% efficient, on a wagon to wheel basis, due to immutable laws of thermodynamics. Electric vehicles using lithium ion batteries are 75-95% efficient. The technology is only getting better, including via power electronics and electric motors. So this is a game changer for light transportation, which becomes >70% electric in our oil models by 2050.

(2) Bottlenecks in battery materials will set the limit on the scale up. Numerically, the largest bottlenecks are in lithium; followed by fluorinated polymers and battery-grade nickel; then graphite and copper. We are less worried about cobalt. Our best data-file into materials used in a lithium ion battery, and their costs, is linked here.

(3) Power grids: efficiency drawbacks. Amidst materials bottlenecks, we think vehicle applications will generally outcompete grid applications. While an EV is 3-4x more efficient than what it replaces, grid scale storage usually has a 10%+ energy penalty. Thus the 65kWh battery in a typical EV saves 2-4x more energy and 25-150% more CO2 each year than a typical grid battery (note here).

(4) Power grids: the best battery is no battery. All batteries have a cost, usually $1,000-2,000/kW, which is re-couped through a storage spread, usually around 20c/kWh for daily charging-discharging (model here). Conversely, there are many loads in the power grid that can shift their demand (e.g., to the times when grids are over-saturated with renewables). This often has no cost. And no efficiency losses. Some of our favorite examples are catalogued here.

(5) Power grids: short-term first. The biggest challenges for ramping up wind and solar stem from short-term volatility (inertia, reactive power compensation, frequency regulation, <1-minute power drops). This requires short-term energy storage first, in the 2020s and 2030s. Many short term batteries can also earn their keep through recuperative energy savings. But note short term energy storage favors capacitor banks, STATCOMs, flywheels, synchronous condensers, supercapacitors. It is debatable whether lithium ion is well suited to short-term smoothing. Eaton has even recently started integrating supercapacitors into its industrial batteries, amidst increasing customer demand for short-term performance (case studies here).

(6) Long-term storage is for the 2040s, if at all. If you cycle your battery 10 times per day, you amortize its capex across 3,650 cycles per year, and the cost per cycle is <1c/kWh. Cycle 1 time per day, and it is 10-20c/kWh. Cycle 1 time per month and you are well above 200c/kWh. The maths are reviewed here. You can also stress test numbers in our pumped hydro model, other battery models. So we do not think long term storage (via batteries or hydrogen) will ever come into the money. We see more opportunity in long-distance power transmission, decarbonized gas, next-gen nuclear; fully decarbonizing future grids while keeping costs below 10-20c/kWh.

(7) Density will improve, but not enough for mass deployment of battery trucks, ships or planes. Today’s lithium ion batteries store 200Wh/kg. In a best case scenario, this could reach 1,250 Wh/kg. Oil products contain 12,000Wh/kg. Thus a battery-powered Class 8 truck will have 70-80% lower range than a diesel truck. And a battery-powered airliner has a range of c60-miles. We do not currently see battery powered trucks, ships or planes going mainstream.

(8) Next-gen batteries: can we de-risk them? There is constant progress and innovation in batteries, to improve density, duration, chemistry, longevity, cost, charging speeds. So we are constantly screening patent libraries. As a general rule we have found incremental innovations easier to de-risk. But we have been less able to de-risk big changes. Replacing lithium with sodium has issues with ionic radius. Solid state batteries often have issues with dendrites and longevity. Redox flow likely works but has 70-75% efficiency.

(9) End-of-life is most unresolved. If there is one TSE research note on batteries, which we think decision-makers should read it is this one, explaining battery degradation, the best antidotes and their implications (lithium upside?, manufacturer upside?). This matters, because despite some interesting inroads, we still do not think the industry has really cracked battery recycling, a potential $100bn pa market in the 2040s.

(10) Which battery companies? We have been most impressed by manufacturing technologies from 24M and CATL, followed by integrated battery offerings from Eaton, Stem and Powin. There are some interesting innovations from Amprius, Enovix, Quantumscape. But so far, we have found it more challenging to entirely de-risk concepts from Sila, Form Energy, Solid Power, Storedot. Please email us if there are any battery technologies you would like us to explore.

Around 60 reports and data-files into batteries and energy storage have led us to these conclusions above; listed in chronological order on our batteries category page. The best way to access our PDF reports and data-files is through a subscription to TSE research.

Renewables plus batteries: co-deployments over time?

More and more renewables plus batteries projects are being developed as grids face bottlenecks? On average, projects in 2022-24 supplemented each MW of renewables capacity with 0.5MW of battery capacity, which in turn offered 3.5 hours of energy storage per MW of battery capacity, for 1.7 MWH of energy storage per MW of renewables.

Co-deployments of renewables and batteries are tracked in this data-file, tabulating the details of over 100 projects that combined a grid-scale battery with their construction of wind and/or solar assets. The average of these projects in 2022-24 added 0.5MW of battery capacity per MW of renewables, with 3.5 hours of energy storage, for 1.7 MWH of energy storage per MW of renewables.

These numbers have all approximately doubled versus a decade ago, when the co-development of renewables plus batteries was a rarity, and tended to occur at smaller scale. This suggests that rising interconnection costs and risks of curtailment are motivating greater deployment of batteries.

A dozen recent renewables plus battery projects are very large in size, ranging from 100-1,000MW of battery storage capacity, almost all being developed in 2020 or thereafter (chart below). For example, the 875MW Edwards & Sanborn solar project in Kern County, California is co-located with 971MW of BESS units from LGChem, Samsung and BYD.

Conversely, the largest batteries from pre-2017 are c30-50MW in size, and many of the technical papers over this timeframe are consciously considering different battery chemistries — lead-acid, sodium-sulphide — rather than today’s projects that are predominantly LFP lithium ion.

The duration of these grid-scale batteries has also increased from 2.6 hours prior to 2020 to 3.5 hours after 2020, with the upper decile projects hacing 5-6 hours of storage (chart below).

It is fine to co-develop renewables with batteries, but it is also more costly. A utility-scale solar project might cost $1,000/kW. A grid-scale battery might cost $1,500/kW. Hence combining 0.5MW of batteries per MW of solar might cost $1,750/kW in total, re-inflating levelized costs of solar by around 50-75%, but still possibly less costly than funding network upgrades.

Our long-term forecasts for power grid capex assume that 0.15MW of grid-scale batteries will be deployed per MW of renewables capacity, comprising a mixture of standalone renewables projects and renewables projects that are co-developed with batteries. And there could be upside?

Companies that stood out in deploying and supplying grid-scale batteries are noted in the data-file.

Compressed air energy storage: costs and economics?

Capex and cash flows for a compressed air storage facility.

Our base case for Compressed Air Energy Storage costs require a 26c/kWh storage spread to generate a 10% IRR at a $1,350/kW CAES facility, with 63% round-trip efficiency, charging and discharging 365 days per year. Our numbers are based on top-down project data and bottom up calculations, both for CAES capex (in $/kW) and CAES efficiency (in %) and can be stress-tested in the model. What opportunities?

Compressed Air Energy Storage (CAES) seeks to smooth out power grids, using excess electricity to compress air into storage tanks or underground reservoirs at high pressures (e.g., 40-80 bar). The energy needed to compress air to different temperatures is plotted below. Electricity can later be recovered later by expanding these high-pressure gases across a turbine.

The round trip efficiency of CAES averages 60-65%, across projects that are sampled in the data-file. We can break down these numbers from first principles, assuming 78% compressor efficiency, 90% turbine efficiency and 97% generator efficiency (matching the numbers in our power plant loss attributions). Another 3-30% will be lost due to compressed gases cooling during storage (see below).

When gases are compressed they tend to heat up. For example, in an isentropic process — where heat is not exchanged with the external environment — compressing air to 30-60 bar will also tend to increase its temperature to 500-600°C. Inevitably, when the gas is stored, however, some of this heat does leak to the external environment, which means that there will be less energy to recover from the gas when it is expanded across the turbine. For more, please see our overview of thermodynamics.

We can model the capex costs of Compressed Air Energy Storage from first principles in the model, by combining our models of compressor costs, storage facility costs and turbine costs. Our numbers also match top-down costs reported for past projects and technical papers into CAES.

Hence our base case estimates for CAES costs require a 26c/kWh storage spread to generate a 10% IRR at a $1,350/kW CAES facility, with 63% round-trip efficiency, charging and discharging 365 days per year. As always, costs vary with WACCs, duration and the number of charge-discharge cycles (chart below).

But generally, CAES costs 30% more than a lithium ion battery storage system. Key reasons are the lower efficiency (discussed above) and 5-10x higher maintenance costs for the moving parts in a CAES system (compared to a LiB with no moving parts).

CAES economics are most competitive when input electricity costs are low and storage duration is increased. One advantage of a CAES system is that it can easily be scaled if the facility has access to a large underground storage reservoir, possibly ranging across thousands-millions of m3, with a tolerance for 40-300 bar pressures. In this case, we think capex costs could fall below $50/kWh for a long-duration battery (LiB comparison here).

Long duration storage leader? In theory a CAES system could thus provide 24-hours of storage for as little 30-40c/kWh. These numbers are generally lower than for 24-hour storage in lithium ion batteries, comparable to redox flow batteries, but still higher-cost than the costs of 24-hour storage in thermal energy storage systems.

Electrochemistry: redox potential?

A flow chart depicting the calculation of a batteries current, voltage, and efficiency providing an overview of electrochemistry.

Batteries, electrolysers and cleaner metals/materials value chains all hinge on electrochemistry. Hence this 19-page note explains the energy economics from first principles. The physics are constructive for lithium and next-gen electrowinning, but perhaps challenge green hydrogen aspirations?

Electric vehicle: battery life?

Electric vehicle battery life will realistically need to reach 1,500 cycles for the average passenger vehicle, 2,000-3,000 cycles after reflecting a margin of safety for real-world statistical distributions, and 3,000-6,000 cycles for higher-use commercial vehicles. This means lithium ion batteries may be harder to displace with novel battery chemistries?

Our forecasts in the energy transition see electric vehicle sales exploding to 200M vehicles per year by 2050 (see below). But the lifetime of an EV is determined by the degradation of its battery, which can be contrasted with the c-20 year typical lifetimes of ICE vehicles.

Hence what requirements for electric vehicle battery life? This question matters if electric vehicle chemistries are going to switch away from incumbent lithium ion battery chemistries, to more novel and more energy dense battery chemistries (see below) such as solid state batteries, silicon anode batteries or sodium-ion batteries.

This data-file contains simple estimates for the number of battery cycles required over the life of different electric vehicles, with back-up workings. For example, a US electric car, driving 10,000 miles per year, at an effective fuel economy of 3 miles/kWh is going to endure around 1,500 battery charging-discharging cycles over a 15-year life.

Commercial vehicles are going to endure 3,000-6,000 charging-discharging cycles over their effective lives, because they are more heavily utilized. For example, a typical taxi covers 45,000 miles per year, while a Class 8 electric truck might cover 200,000 miles (chart below). The data-file also covers other vehicles from e-scooters to mine trucks.

Within each category, there is also going to be a distribution, impacting the design considerations of vehicle manufacturers. For example, only a small portion of cars get into potentially fatal accidents over their operating lives, and yet all modern cars have safety features. Designs are determined not by the average conditions but by the extremes. Although we do wonder if any vehicle manufacturers will bring out cheaper EVs specifically targeted for low use urban drivers (dark green bar above).

If annual miles driven for a US passenger vehicle follow our favorite statistical distribution, the Boltzmann distribution, then an average of 10,000 miles driven per year means that c10% of cars will drive over 15,000 miles per year and 1% will drive over 20,000 miles per year. Hence vehicle manufacturers might realistically target 2,000-3,000 battery cycle lives to capture the full range of driving behaviours (chart below).

These numbers all assume that vehicle operators respect recommendations not to charge a battery beyond 80% of its state of charge, or below 20% of its state of dischange, as degradation is amplified outside of these limits, due to the physics of the Nernst Equation. Consumer behaviours will also impact battery life. We recommend our overview of battery degradation (below).

Another way to increase the cycle life of a vehicle is to add a bigger battery, as a larger battery needs to be cycled less frequently to deliver the same overall amount of energy across a given calendar year. This comes with the benefit of a longer range, but the drawback of higher battery costs, materials requirements and vehicle weight. More efficiency vehicles also help, which may accelerate the trend towards lightweighting (carbon fiber, aluminium, advanced polymers) and Rare Earth permanent magnets.

All of these considerations make us think lithium ion batteries are likely to remain the incumbent solution for electric vehicles, ramping rapidly for passenger cars, but less so for larger commercial vehicles, whose CO2 must be abated by other means in our roadmap to net zero.

Within lithium ion batteries, we are most excited by advanced materials improving cell voltage and lowering degradation, including using fluorinated polymers.

Our underlying calculations regarding electric vehicle battery life spans are available via the download button below.

Thermal energy storage: heat of the moment?

Thermal energy storage will outcompete other batteries and hydrogen for avoiding renewable curtailments and integrating more solar? Overlooked advantages are discussed in this 21-page report, plus a fast-evolving company landscape. What implications for solar, gas and industrial incumbents?

Thermal energy storage: cost model?

This data-file captures the costs of thermal energy storage, buying renewable electricity, heating up a storage media, then releasing the heat for industrial, commercial or residential use. Our base case requires 13.5 c/kWh-th for a 10% IRR, however 5-10 c/kWh-th heat could be achieved with lower capex costs.

Thermal energy storage solutions aim to help integrate solar and wind into power grids, by absorbing excess generation that would otherwise be curtailed, and then re-releasing the heat later when renewables are not generating.

Different storage media are compared in one of the back-up tabs of the model. However, one-third of the companies in our thermal energy storage company screen are pursuing molten salt systems, hence our thermal energy storage model focuses on this option.

In our base case, the cost of thermal energy storage requires a storage spread of 13.5 c/kWh for a 10MW-scale molten salt system to achieve a 10% IRR, off of $350/kWh of capex costs. Costs are sensitive to capex, utilization rates, opex, electricity prices and round trip losses. The sensitivities can be stress tested in the data-file.

Capex costs of thermal energy storage may be reduced below our base case estimate, which has been built-up using the same input assumptions as our broader battery cost models. Larger systems require proportionately more storage material, larger tanks, and more insulation. But other lines in the capex build up do not change, and hence these costs deflate in MWH-terms.

The round-trip efficiency of thermal energy systems can also be higher than we might have naively expected, possibly in the range of 85-95%. The physics is modeled from first principles in other back-up tabs of the data-file. As a generalization, a large and well-insulated thermal energy storage system loses 1-2% of its stored heat over the course of 24-hours.

The full data-file contains the workings behind our recent deep-dive into thermal energy storage. We have also included similar estimates for residential-scale storage, adding an electrically heated hot water tank to absorb excess renewables, which looks simple and can be highly economical. Please download the data-file to stress test all of our numbers.

Renewable grids: solar, wind and grid-scale battery sizing?

Grid-scale battery sizing

How much wind, solar and/or batteries are required to supply a stable power output, 24-hours per day, 7-days per week, or at even longer durations? This data-file stress-tests grid-scale battery sizing, with each 1MW of average load requiring at least 3.5MW of solar and 3.5MW of lithium ion batteries, for a total system cost of at least 18c/kWh.

Start by modelling a power demand curve. Then model how much wind or solar would need to be installed to provide this electricity demand across a comparable timeframe. Then model how big a battery is required to move the renewables to align with the timing of the power demand curve. This data-file works through the maths, for different batteries, including their round trip efficiencies, and their costs.

The minimum possible requirement for a fully solar-powered electricity grid is that each 1MW of load requires 3.5MW of solar modules and 3.5MW of lithium ion batteries with daily charging-discharging, in a location where every day is perfectly sunny, with no clouds, and no seasonality, for a total levelized cost (LCOTE) of 18c/kWh.

Introduce volatility into the weather pattern, and the requirement for a fully solar-powered grid is that each 1MW of average load requires 5MW of solar modules and 9MW of lithium ion batteries with full charging-discharging every 1.5 days on average, and a total levelized cost (LCOTE) of 35 c/kWh. For more detail, please see our data-file into the volatility of solar generation.

Grid-scale battery sizing
Sizing of a solar array and battery module to supply a 100MW load for 30-days including cloudy days

Introduce seasonality in the weather pattern, with 50% lower solar output in winter versus the summer, and the requirement for a fully solar-powered grid is that each 1MW of average load requires 6MW of solar modules and a somewhat insane 235MW of lithium ion batteries with full charging-discharging every 70-days on average, for a total levelized cost (LCOTE) of 800c/kWh. Which is also somewhat insane.

Grid-scale battery sizing
Sizing of a solar array and battery module to supply a 100MW load for 365-days including seasonality

Wind numbers are more demanding than solar numbers, all else equal, because the sun rises and sets daily (helping the utilization rate of the batteries), while wind can incur 2-3 windy days followed by 2-3 non-windy days (hurting the utilization rate of batteries). For more detail, please see our data into the volatility profile of wind generation.

Grid-scale battery sizing
Sizing of a wind farm and battery module to supply a 100MW load for 2-3 weeks including still days

Redox flow batteries are particularly helpful for integrating larger shares of renewables, and are modelled to result in total system costs that are c50% lower than using lithium ion batteries at grid scale. Please see our deep-dive research note into redox flow batteries.

This data-file provides underlying workings into renewable asset sizing, grid-scale battery sizing and total system costs for our recent research into renewables’ true levelized cost of electricity (LCOTE).

Thermal energy storage: leading companies?

This data-file is a screen of thermal energy storage companies, developing systems that can absorb excess renewable electricity, heat up a storage medium, and then re-release the heat later, for example as high-grade steam or electricity. The space is fast-evolving and competitive, with 17 leading companies progressing different solutions.

Thermal energy storage solutions aim to help integrate solar and wind into power grids, by absorbing excess generation that would otherwise be curtailed, and then re-releasing the heat later when renewables are not generating.

Across the 17 leading thermal energy storage companies, the average one was founded in 2015, has c50 employees, is at TRL 6 and aims to convert excess renewable electricity into 750ºC heat.

Thermal losses are usually limited to 1-2% per day, and these systems have the ability to re-release the heat at MW-scale over an average period of c15 hours, in a system that will last c30-years. The data-file tabulates disclosures into these different dimensions.

Different solutions. Around one-third of the companies are using molten salt as a heat storage medium, one third are using blocks or bricks, and one-third are using other advanced materials.

Details are tabulated for each company, showing the variability across all of these parameters, plus 3-10 lines of notes, from company materials, which stood out as interesting to us.

Leading thermal energy storage companies in the screen include Kyoto Group, Rondo Energy, SunAmp, Eco-Tech Ceram, Energy Nest and Antora Energy, plus fifteen other firms.

This screen is discussed in our overview of thermal energy storage. It also feeds into our key conclusions on energy storage.

Redox flow batteries: for the duration?

Redox flow batteries

Redox flow batteries have 6-24 hour durations and require 15-20c/kWh storage spreads. They will increasingly compete with lithium ion batteries in grid-scale storage. Does this unlock a step-change for peak renewables penetration? Or create 3-30x upside for total global Vanadium demand? This 15-page note is our outlook for redox flow batteries.

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