Role of batteries in energy transition

Energy storage: top 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.

Solar plus batteries: the case for co-deployment?

The percentage of solar output dispatched to the grid depending on the capacity of the interconnection and the capacity of co-deployed batteries.

This 9-page study finds unexpectedly strong support for co-deploying grid-scale batteries together with solar. The resultant output is stable, has synthetic inertia, is easier to interconnect in bottlenecked grids, and can be economically justified. What upside for grid-scale batteries?

Solar+battery co-deployments: output profiles?

Output of a solar+battery co-deployment power plant on a typical summer day.

Solar+battery co-deployments allow a large and volatile solar asset to produce a moderate-sized and non-volatile power output, during c40-50% of all the hours throughout a typical calendar year. This smooth output is easier to integrate with power grids, including with a smaller grid connection. The battery will realistically cycle 100-300 times per year, depending on its size.

The output from a standalone solar installation is notoriously volatile, varying +/- 5% every 5-minutes on average, plus sudden power spikes and drops, and achieving an annual utilization factor of just 20%.

But how does co-deploying solar+batteries lower the volatility? This data-file uses real-world data, from an Australian solar asset, measured at 5-minute intervals, and then applies simple rules about when to flow power into and out of the batteries, to maximize the delivery of 100MW, smooth, non-volatile power.

The solar+battery output also includes synthetic inertia and frequency regulation, which helps rather than hinders overall grid stability.

The title chart above shows how the output profile of our solar+battery system might behave on a summer’s day, with the net asset providing 100MW to the grid for 24-hours. Excess solar is shunted to the battery throughout the day. Then the battery is gradually discharged to zero after sunset. This model works well in the summer.

However solar generation is highly seasonal, and on a winter’s day, this exact same battery does help to keep output stable at 100MW, but it only achieves 20% of a full charge-discharge cycle, as there is simply not enough solar generation to fill the battery. The bigger the battery, the less likely it gets full in the summer, and the less utilized it is in the winter.

Output of a solar+battery co-deployment power plant on a typical winter day.

This can be stress-tested in the data-file. We can also calculate the number of charge-discharge cycles that different batteries achieve, if they are charged exclusively with solar generation. Some decision-makers assume daily charging-discharging when modeling the economics of batteries, but this is shown to be much too optimistic (below).

Number of charge-discharge cycles achieved by a battery per year depending on the ration of battery capacity to co-deployed solar capacity

Overall, remarkably, solar+battery co-deployment model means that a 275MW solar installation + a 275MW battery can dispatch 95% of its generated output through a mere 100MW grid connection. This is why co-deploying renewables+batteries can help to surmount power grid bottlenecks. And in turn, this is why we think battery co-deployment is accelerating.

How much solar power is dispatched (ie utilized) for a 275MW solar project depending on the size of its grid connection and capacity of co-deployed batteries.

If a battery is run purely for solar smoothing, with 1MW of battery capacity per MW of solar, then the battery will tend to achieve 180 charge-discharge cycles throughout the year, and it will allow a 275MW solar asset to output precisely 100MW to the grid in c50% of the time throughout an entire year (but still producing no power about 40% of the time).

The production profiles vary month by month. The results vary with battery sizing and charging-discharging rules. These sizings and rules can be stress-tested in the data-file, to assess how different-sized batteries result in different dispatch rates and charge-discharge cycle counts.

Lithium ion battery volumes by chemistry and use?

Global lithium ion battery demand broken down by demand category and battery technology. Data from 2011 to 2023 and projected to 2030

The lithium ion battery market reached 900GWH in 2023, representing 7x growth in lithium ion battery volumes in the past half-decade since 2018, and 20x growth in the past decade since 2013. Volumes treble again by 2030. This data-file breaks down global lithium ion battery volumes by chemistry and by end use. A remarkable shift to LFP is underway, and NMC sales may even have peaked.

The lithium ion battery market reached 900GWH in 2023, representing 7x growth in the past half-decade since 2018, and 20x growth in the past decade since 2013. This data-file breaks down global lithium ion battery volumes by chemistry and by end use, by aggregating past estimates from technical papers and forecasting agencies.

Over 70% of the lithium ion battery market is for electric vehicles, followed by grid-scale energy storage, and incorporation into electronic devices.

Our forecasts for lithium ion battery sales through 2030 hinge on our outlook for electric vehicles as reflected in our global vehicle sales database, and our outlook for co-deployment of batteries with renewables, as reflected in our global power grid capex model. In turn, these forecasts impact the demand for battery materials such as lithium, graphite, nickel, cobalt and fluorinated polymers.

Cathode chemistry has shifted markedly over time, which is reflected in the data-file. Prior to 2013, the lithium ion battery market was dominated by LMO/LCO. At peak in 2019, NMC batteries had over 60% market share, and NMC incumbents were declaring victory over LFP cells, whose share, in turn, was projected to fall to zero throughout the 2020s.

Lithium ion battery costs: materials and manufacturing?

Reality has turned out quite different, due to amazing deflation in LFP batteries (see above), especially from Chinese suppliers such as CATL and BYD. China’s electric vehicles could comprise two-thirds of all global EV sales in 2024 and LFP dominates in China. If LFP continues gaining share to around 75% of lithium ion batteries by 2030, or higher, then demand for NMC cells may have peaked in 2023.

Innovator’s dilemma? It is truly remarkable to look back at technical papers published by LG Energy Solutions (larger NMC battery producer in the world) and similarly from McKinsey, back in 2019, arguing that NMC would dominate the industry in the future, and that LFP’s market share would gradually fall to zero (!), due to its inferior ionic mobility, hygroscopicity, charge-monitoring, voltage, density and [sic] longevity. These studies did not, however, clock LFPs’ lower costs.

Maybe there is a lesson here about the importance of unbiased first-principles analysis, supported by economic models, when assessing energy transition technologies. There is a danger of confirmation bias, within an ocean of possible data-points that may support pre-existing positions. But costs often turn out to be the single most important variable.

Our own first-principles analysis into the rise of LFP is re-capped below. The data-file tracks how NMC leaders from 2019m such as LGES and SK On have shifted their perspective, based on technical papers, news stories and the number of patent filings. In 2019, LG literally wrote that “NMC is the right choice… LFP should not be preferred” yet by 2024 it signed a contract to supply LFP cells to Renault’s Ampere EVs from a facility in Poland. It may take 3-5 years for LGES and SK On to catch up with CATL and BYD in LFP.

LFP batteries: cathode glow?

Lithium ion battery volumes in GWH per year, are broken down by end use, and by cathode chemistry, in this data-file, triangulating between technical papers, going back to 2011, and forecast out through 2030.

LFP batteries: cathode glow?

Structural comparison of NMC and LFP cathodes.

LFP batteries are fundamentally different from incumbent NMC cells: 2x more stable, 2x longer-lasting, $15/kWh cheaper reagents, $5/kWh cheaper manufacturing, and $25/kWh cheaper again when made in China. This 15-page report argues LFP will dominate future batteries, explores their costs, and draws implications for EVs and renewables.

Pumped hydro: generation profile?

Monthly charge, discharge, and the resulting net discharge for the Tumut 3 pumped hydro storage project. Data from 2021-2023.

Pumped hydro facilities can provide long-duration storage, but the utilization rate is low, and thus the costs are high, according to today’s case study into the pumped hydro generation profile within the Snowy Hydro complex in Australia. Tumut-3 can store energy for weeks-months, then generate 1.8 GW for 40+ hours, but it is only charging/dischaging at 12% of its nameplate capacity.

Tumut-3 is the largest single generating facility in the Snowy hydro and pumped hydro project, in New South Wales of Australia, whose history goes back to 1949.

1,800MW of power can be generated when up to 4,300 m3/s of water descends 150m under gravity through 6 x 300MW Toshiba turbines, from the 2,000 hectare Talbingo Reservoir into the 400 hectare Jounama Pondage, then onwards into the Blowering hydro plant.

Equally, 600MW of power can be ‘stored’, when 300 m3/s of water is pumped back up from Jounama to Talbingo, by each of 3 large pumps.

Real-world data into Tumut-3 matters generally for the costs of using pumped hydro to backstop renewables, and specifically for the A$12bn and 2.2GW Snowy 2.0 project, under construction, and featuring 27km of tunnels, the longest of any pumped hydro station ever built. Snowy 2.0 is directly adjacent to Tumut-3, using Talbingo as its lower reservoir, and cycling water by 700m into the Tantangara Reservoir.

Hence we have compiled the charging and discharging data, at 5-minute intervals for Tumut-3, across all of 2021-23 (over 50MB of data), using data from AEMO.

Example: 5-minute-by-5-minute generation on the single most active and single least active day of September-2023, at the Tumut-3 pumped hydro storage facility.

Long duration storage is clearly provided by the facility, as shown in the scatter plot below. Monthly charge and discharge are 82% correlated, but not identical. Statistically, 70% of the energy stored by Tumut-3 is re-released in the same month, and the other 30% is longer-duration.

If we zoom in on months with very large quantities of discharging, but small quantities of charging, such as May-2021 or November-2022, then we can see up to 40-hours of cumulative discharging. This is about 10x longer than a lithium ion battery.

Even longer storage durations could be achieved by constructing larger pumped hydro facilities, with larger reservoirs, both upstream or downstream. This is really the only viable long-duration battery, available at large scale today, while development progress continues with redox flow batteries, compressed air or novel chemistries.

However, the key challenge is low utilization. On average from 2021-23, charging occurred at a rate of 1.6 MWH of charging per day per MW of capacity, resulting in 1.2 MWH of discharging per day per MW of capacity.

One reason for the low charging-discharing activity at Tumut-3 in 2021-23 is that heavy rainfall occured in 2022, and thus there were risks of the Blowering Reservoir and the Tumut River flooding. Some may argue that this is simply the nature of the beast of managing hydro assets. Others may wish to adjust future utilization factors upwards.

Either way, and for comparison, a lithium ion battery with daily charging and discharging achieves 4 MWH per day per MW of capacity. And the base case in our pumped hydro cost model is for 5 MWH per day per MW of capacity, which in turn requires a storage spread of 25 c/kWh. At 2 MWH per day of charging per MW of capacity, then the same model requires a storage spread of 60c/kWh.

Pumped hydro: the economics?

The key challenge, borne out in this case study, is that long-duration batteries tend to achieve low utilization, which hurts their economics. Hence we think the rise of renewables will entrench natural gas.

Back up: does ramping renewables displace gas?

Finally, the evidence suggests that a typical pumped hydro generation profile is less actively used for short-term grid smoothing than lithium-ion batteries. This is borne out by charts in the data-file versus charts in our grid-scale lithium ion battery case study. Data into the charging-discharging by time of day, are shown in the data-file. Underlying data behind all of our charts are also contained in the data-file.

Grid-scale battery operation: a case study?

Grid-scale batteries are not simply operated to store up excess renewables and move them to non-windy and non-sunny moments, in order to increase renewables penetration rates. Their key practical rationale is providing short-term grid stability to increasingly volatile grids that need ‘synthetic inertia’. Their key economic rationale is arbitrage. Numbers are borne out by our case study into battery operations.

Victorian Big Battery was the largest grid-scale battery in the world, when it was installed in Victoria, Australia in 2021. It was installed by Neoen and consists of 212 x 3MWH Tesla Megapacks. Total capacity is 300MW on a power basis and 450MWH on a storage basis (as can be contrasted in our MW/MWH battery comparison).

How does a grid-scale battery operate in practice? To answer this question, we collated an entire year of load and generation data for Victorian Big Battery, using data from Aemo.

Across the entirety of 2023, Victorian Big Battery absorbed 122GWH of power and discharged 102GWH of power, for a total net efficiency of 84%. This is in line with our typical estimate for a grid-scale lithium ion battery to have c85% efficiency.

The utilization of the battery equates to 0.7 charge-discharge cycles per day, as shown in the chart below, in MWH of charge-discharge per day per MWH of storage capacity. However, the utilization rates varied throughout the year.

Rate of charging and discharging for the Victorian Big Battery throughout 2023.

Outside of summer months, utilization of Victorian Big Battery averaged 1MWH of charge-discharge per day per MWH of storage capacity. The profile for the median day is shown in the chart below.

Some commentators argue that the main role of grid-scale batteries will be to enable higher solar penetration in power grids, by ‘storing up excess sunlight in the middle of the day, and then re-releasing that energy at night’. This is not entirely borne out by Victorian Big Battery.

The primary economic rationale for Victorian Big Battery has been economic arbitrage. The battery consistently buys power during times of low prices (1am-5am, 10am-3pm, chart below) and sells power at times of high prices (6am-8am, 4pm-8pm).

Power prices in Victoria, Australia for over 2023.

The battery is reasonably good at economic arbitrage, but not perfect. When prices were negative in May-2023, Victorian Big Battery was able to charge about 80% of the time. When prices surpassed A$200/MWH, it was able to discharge about 80% of the time. The average storage spread is calculated in the data-file, but was lower than the level we think is necessary for economic returns in our grid-scale battery models.

Percentage of time the Victorian Big Battery spent charging, discharging, and idling for different power prices.

What is helping economics is that the battery is also providing crucial smoothing services in the grid. Inertia and frequency control come for free with rotating generators. But in renewable heavy grids, these are provided as an ancillary service by grid-scale batteries. This is visible in the volatility of charts in the data-file. 5-minute by 5-minute volatilty is +/- 40MW.

Moreover in summer months, Victorian Big Battery is operated almost entirely as a contingency reserve. Specifically, this means that it is not charged and discharged to its maximum extent each day, but sits with a high state of charge, and provides 250MW of system integrity protection (SIPS), including synthetic inertia for solar-heavy grids, and the capacity to kick in should some large new load start up, or some large generation source suddenly disconnect. This is part of capacity markets.

Underlying data into real-time battery charging and discharging, at 5-minute intervals, are available in the data-file, for a selection of months (Apr-23, May-23, Jan-23) and compared with wholesale grid prices. It is interesting to pour over the charts, and see how batteries behave minute-by-minute, day-by-day and in response to pricing signals.

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?

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