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Seeking Consensus on the Externalized Costs of Battery Storage

What is meant by “externalized costs”?

Externalized costs are costs associated with energy consumption which is not reflected in the selling price of the energy. These costs are directly or indirectly paid by other sectors of the economy in forms such as increased healthcare expenditures, losses in property values, increased costs associated with natural disasters, and a reduction in the free services rendered by the biosphere.

Externalized costs of battery storage

Environmental impacts of battery technology arise primarily from substantial quantities of embodied energy required and the mining of rare-earth materials. Li-ion batteries are by far the most thoroughly studied subject and we will assume that their external cost also applies to other battery chemistries.

A very recent review of 113 studies has provided a good summary of the environmental impacts of Li-ion batteries.  As can be seen in the summary graph below, significant scatter is present between different studies and different Li-ion battery chemistries.

Key for environmental impacts: ADP = Abiotic depletion, AP = Acidification, GWP = global warming potential, EP = Eutrophication, ODP = Ozone depletion and HTP = Human toxicity.

Key for battery chemistries: LFP = Lithium-ion phosphate, LTO = Titanate, LCO = Lithium Cobalt oxide, LCN = Lithium cobalt nickel oxide, LMO = Litium manganese oxide, NCM = Lithium cobalt manganese oxide, NCA = Lithium nickel cobalt aluminium oxide.

The global warming potential is the most commonly studied topic in the literature and returns average equivalent CO2 emissions of about 110 g/Wh. For perspective, this implies a CO2 cost of 6.6 tons for the 60 kWh battery pack of the Chevy Bolt – equivalent to 40000 miles of gasoline emissions in a Prius.

However, the study notes that, although global warming potential is the most studied environmental impact of Li-ion batteries, it is arguably less important than other aspects. The following graph is presented where average environmental impacts are normalized by the total impact in Europe.

It is clear that global warming potential is mild relative to abiotic depletion, acidification and human toxicity. When monetizing externalities, it therefore appears reasonable to express other externalities as a cost that is somewhat larger than the cost of climate change. Assuming a 50/50 split between deployment in developed and developing countries, the CO2 price comes to $36/ton. If we double that to account for other external costs, it amounts to $72/ton or $8/kWh of battery capacity, which is quite low relative to the internalized battery costs. We will add another 50% for externalities related to other components (inverter, cabling, BOS), bringing the total up to $12/kWh. Assuming an average of 50% depth of discharge per day for 10 years at a discount rate of 5%, the total externality amounts to $10/MWh of stored electricity.

To compare to internalized costs, note that the Tesla Powerpack hardware currently costs $420-630/kWh depending on scale.  Using $500/kWh in the internalized costs calculations presented earlier returns an energy storage cost of about $400/MWh for an average of 50% depth of discharge per day.


If you have a number that differs significantly from the estimates given above, please add it in the comments section below together with an explanation and a reference. 

Schalk Cloete's picture

Thank Schalk for the Post!

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Schalk Cloete's picture
Schalk Cloete on August 8, 2017

DATA: Externalized costs of battery storage: $10/MWh according to the estimates in this article.

Guy Dauncey's picture
Guy Dauncey on August 8, 2017

Do you know which chemical is causing global warming, and needing a GWP?

Schalk Cloete's picture
Schalk Cloete on August 9, 2017

As I understand it, ADP accounts for the potential economic impacts of peaking production of a valuable resource due to depletion. A good recent example is the plateau of conventional oil production that kept oil prices above $100/barrel for a long time even though the average production cost of oil remained about $30/barrel. This caused a large wealth transfer from oil importers to oil exporters and therefore had broad adverse economic consequences.

I’m not so well versed in the availability of the materials used in battery manufacturing, but I have seen a fair share of articles warning about material supply issues associated with more optimistic BEV and stationary storage expansion scenarios. The challenge is during the multi-decade growth phase where a lot of material has to be extracted from the ground. Recycling can only become the primary source once we approach a steady state situation.

The graph is normalized by the total impact of all economic activity in Europe. For example, the amount of CO2 produced by battery manufacturing in Europe is only a 2E-14 fraction of the total CO2 equivalents produced in Europe because it is such a small activity. Seems a bit too small though, but that’s what the research paper says…

Yosef Shirazi's picture
Yosef Shirazi on August 9, 2017

Every material and process results in some GWP. Li-ion batteries contain sizable fractions of aluminum, copper, lithium cobalt and graphite. Each requires mining/extraction and processing/concentrating. Plus the transport of these rely on diesel and fuel oil.

To a first approximation, I’d be willing to bet the relative cost of each material/component in the battery indicates the relative GWP of that material/component.

Nathaniel Pearre's picture
Nathaniel Pearre on August 10, 2017

You do a wonderful job of covering an apparently thorough survey paper, but then you casually throw in the assumption that BES utilization will be half a cycle/day. Due to the strong relationship this value has on your final cost finding, I’d say you really need to back it up.
Frequency Regulation, for example (to which many ESS are tasked) often is attributed an energy throughput of more like 0.1 kWh/kWh_cap/HOUR, or more than 2 full cycles/day. This specific application, then, would reduce your resulting costs by a factor of more than 4.
In contrast, installations for T&D upgrade deferral or as peaker replacements may cycle far less than that (for that one application)… though again, any BES operator will likely try to do something, or more than one something, at all times to maximize revenue.

Schalk Cloete's picture
Schalk Cloete on August 11, 2017

You make a good point. Battery economics improve for applications like frequency regulation. The selection of half a cycle a day is for potential high-volume future price arbitrage applications.

You sound like you have good expertise on the topic. How large do you think is the potential battery market for low-volume applications like frequency regulation?

Engineer- Poet's picture
Engineer- Poet on August 11, 2017

AC Propulsion was all over this in the late 90’s.  See:

There’s gold in the other white papers too:

Nathan Wilson's picture
Nathan Wilson on August 12, 2017

Your point about frequency regulation is certainly important for investors & suppliers of grid batteries, at today’s small market size.

But for the clean energy community, the big question about grid-connected batteries is can they allow solar to supply a large fraction of our night-time and evening power. The frequency regulation application is two orders of magnitude smaller than the other two (which have a limit of 1 cycle per day, before accounting for clouds and reserve capacity).

In fact, when windpower is deployed alongside solar, the opportunity for batteries gets even smaller, since the wind can be strong or weak for days at a time. This means fewer potential battery cycles per year.

Willem Post's picture
Willem Post on August 13, 2017


1) Frequency regulation is about damping the variable outputs of solar and wind systems.

Such batteries are kept at about 60% charged, so they could ramp up to 95% of rated (above 95% shortens life) and ramp down to 25% of rated (below 25% shortens life), for a 70% swing.

Normally the percent swing is much less during frequency regulation.

2) Shifting PV solar from midday to late afternoon/early evening usually is not profitable, unless time of day rate differentials are very large.

3) Such PV solar energy shifting may be profitable, if a grid operator imposes high forward capacity charges and high forward transmission charges on utilities, as does ISO-NE.

A utility typically reduces such charges with diesel generators, gas turbine generators. The latest approach is heavily subsidized battery systems.

4) Average EVs and average ICVs have about the same CO2 emissions, on a lifetime basis.

High mileage ICVs, say 40-plus mpg, have less CO2 than an average EV, on a lifetime basis

EVs with large batteries, such as Tesla, have more CO2 emissions than an average ICV, on a lifetime basis.

Nathaniel Pearre's picture
Nathaniel Pearre on August 16, 2017

Frequency Regulation is currently, as far as I know, something like 1% of load, or something like 4 GW of capacity in the US, on average.
As Willem Post obliquely points out, increases in PV and wind will likely increase that market size somewhat, while the much faster response times of ESS will tend to shrink it, if they become a major fraction of its provision.

In a daily arbitrage application, if round-trip efficient allows it to be economic at all, why wouldn’t it be a full cycle/day? Are you anticipating a full cycle, but price deltas to only get where they need to be every other day?

Schalk Cloete's picture
Schalk Cloete on August 16, 2017

You would only be able to approach one full cycle per day in a country near the equator with lots of solar PV and almost no cloud cover. For the rest of the world, seasons, clouds, randomly varying wind power output, weekends, holidays and the like will strongly affect the possible buy-sell spread from day to day, making it impossible to profitably run regular daily storage cycles.

Nathaniel Pearre's picture
Nathaniel Pearre on August 17, 2017

The is no electrical jurisdiction that I’ve ever seen data for that does not have a strong daily load signal. Load varies quite predictably, with day-ahead forecasts generally within 2%. In my jurisdiction (1200 MW average load system), the day-night variation is fairly consistent throughout the year at about 300 MW, or about 25% of load. Loads fall between 10pm and 1 am, and back up ~5-8am.
-Seasons, weekends, and holidays have almost no impact on that trend; they change the average load, but not the daily variability.
-Clouds (at least intermittent clouds), wind output and the like would most likely increase, rather than decrease, the potential number of cycles batteries could run in a day.

Schalk Cloete's picture
Schalk Cloete on August 18, 2017

Sure, that is mostly the case today. The important thing for prices is not load, but load minus must-run generation (most importantly wind and solar). As wind and solar scale up beyond the 5% global generation level of today, the factors I mentioned above will start to introduce a lot of randomness in the daily price cycle.

Take a look at the electricity price data from that great renewable energy experiments funded by German and EU taxpayers: You will clearly see that there is no chance for regular daily price arbitrage.

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