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While Pumped Hydroelectric Energy Storage (PHES) development has stalled in much of Europe and the USA, in the People’s Republic of China development is booming and the installed capacity had exceeded 22.5 GW by the end of 2014. This moves China into second place for installed pumped hydro globally above the USA which has approx. 21 GW; only Japan has more with 24.5 GW.

In addition, there is currently an additional 11.5 GW of pumped hydro under construction in China which is likely to see it take the lead by 2017. Japan is also currently constructing 3.3 GW of additional pumped storage. Figure 1 shows the development of PHES in Europe, Japan, China, USA and India.

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Development of Pumped Hydroelectric Energy Storage in Europe, Japan, China, USA and India

Figure 1: PHES development in Europe, USA, China, Japan and India. Data from numerous sources including Buy Ambien Fast Delivery. Available in text format Diazepam Kopen Amsterdam or from the Buy Phentermine Us Pharmacy.


While there are undoubtedly many reasons why investors in China and Japan are currently more willing to fund PHES schemes than those in Europe and the USA, the main difference seems to be due to the different regulatory and market structures that exist. In much of the US and Europe, PHES must be rewarded by the market and compete for services that are generally provided by power generation units – and it is treated in a very similar manner to these units. Treating electricity storage as generation makes little sense as storage makes pretty poor generation – the second law of thermodynamics forbids it from outputting more electricity than that which is inputted. Crucially, legislation normally forbids Transmission and Distribution (T&D) network operators from owning PHES (as well as generation). This means it is difficult to reward PHES for its use as a network asset and although the storage could provide benefits across the wider electrical network, the revenue available to them only reflects a small fraction of this value.

In China and Japan PHES plants are rewarded in a cost-of-service manner and can be used as network assets. The network operators can then dispatch these plants as they require for a variety of uses, including ancillary services (frequency response, voltage support, fast reserve etc), peak electric capacity and network congestion alleviation. If the plant can introduce an overall cost saving to the wider network then it is worth the investment.

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A few weeks ago I gave a talk at the UKES energy storage about the work we are doing in Birmingham on the value of distributed energy storage systems. The talk was specifically related to our case study of the Birmingham University main campus as a potential location for a “behind-the-meter” energy storage device. In the introduction I briefly mentioned that there appear to be three main business model classifications for energy storage operation. These are; cost-of-service, direct market participation and behind-the-meter energy storage. This post aims to explain these classifications and expand on how a unique business model for energy storage may use aspects from one or more of these classifications.

There appear to be three main “umbrella” business model classifications under which energy storage could operate in a power market. The term “umbrella” is used because there are very many sub-model variations that can sit underneath one of these terms, and indeed a specific business model can have aspects of all of the umbrella models, however for explanatory purposes still seems useful to broadly classify the models in this manner.

Buy Xanax DublinHow can energy storage make money?

  1. “Cost-of-service”

In this model, the cost of the energy storage is included in the final utility cost (electricity bill) to the customer. Ideally the price would be set based on the costs incurred in providing the service. In practical terms of electricity and electrical energy storage this translates to the storage operator being paid a regulated return on investment. This would probably constitute a part of the final electricity bill to the customer. This is a business model that would be typical of a vertically integrated utility, i.e. a nationalised electricity system. However aspects of this model could be introduced in a competitive electricity market, for example by having third parties compete to provide the energy storage service, but rewarding them in the a regulated manner. Typically this would arise out of an integrated resource plan in line with public policy (for example a mandate requiring a certain level of storage, much like targets for a certain percentage of renewables).

  1. Direct participation in a competitive market

In this model, a storage operator would notice that there was an opportunity to earn a return on their investment through taking advantages of the prices offered in the competitive electricity market. Their participation in the market would then reduce the average electricity price slightly (or the price for whatever service they were offering – for example price of fast reserve, frequency response etc) and in doing so increase the global surplus, that is the consumer surplus plus the producer surplus. Consumer surplus is the difference between what the consumers would pay for the commodity of interest and it’s market price, and producer surplus is the difference between the market price and the price they would be willing to accept. To be effective this model ultimately relies on the energy storage being able to provide a market-service cheaper than current alternatives. This market participation could include entering in long term power purchasing agreements with other market players and/or contracting its services to other market players. The government can also perturb the market through the addition of subsidies to attract investment in technologies which would not otherwise be profitable – for example renewable subsidies. These subsidies will then encourage the development of certain technologies favored by public policy.

  1. “Behind-the-meter” energy storage

This refers to energy storage devices that are located on the consumer’s/generator’s/end-user’s side of the electricity meter and off-grid energy storage applications. In these cases the generator/consumer/end-user would analyse their own energy economics to determine the viability of the storage unit. This could depend on the available energy-tariffs, any renewable incentives, the value of increased reliability, the perceived value of increasing consumers own renewable energy use, etc. A behind-the-meter energy storage device could also theoretically participate in the competitive electricity market provided there were no regulatory barriers to entry from this point (for example as a form demand response). This model includes energy storage owned by a large utility with a portfolio of power generating plants (etc) that is used for internal trading.


Action under each of these umbrella models has associated issues and barriers. For example the barriers for “cost-of-service” type are probably highest, as it likely requires significant changes in utility planning which are slow to occur even if they are very well aligned with public policy goals. Direct entry in a competitive market has less barriers to entry, however two significant problems are that real electricity markets are never perfectly “competitive” and participation in a competitive market carries a significant risk (i.e. market conditions and thus economics can change over time). In practice there are also market regulations that can stop storage from being able to compete for some market services. The behind the meter case should have the least barriers, but entry into this market would likely require a very cheap technology with good performance. A storage device that could be economical behind the meter of domestic consumers is probably the most favourable for an energy storage developer as it offers the largest customer base for their product.

As I’ve already mentioned, an individual business model may include aspects of some or all three of these umbrella model types. For example, electricity storage would be a useful transmission asset but under current UK market rules transmission and distribution companies are generally prohibited from owning storage assets (as well as generation). To get around this the storage could be owned by a third party but be rented and operated by the transmission/distribution company as a transmission asset, and the storage operator rewarded on a cost-of-service basis. Third parties would then compete with each other to provide this energy storage service. This is essentially what happens with the ancillary services market, except that the storage provider can only provide one use out of many. Another example of a business model involving aspects of two of these umbrella models would be a behind-the-meter storage device used to firm the output from a wind farm that also provided the market with frequency response.


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Ben Cruachan Pumped Hydroelectric plant, Scotland, UK

One interesting point to note is that in the UK, all of our bulk storage facilities (four pumped hydro plants – Dinorwig, Ffestiniog, Ben Cruachan, Foyers) were constructed under cost-of-service models, at a time when the electricity industry was a nationalised utility. They are now all owned by utilities with a portfolio of generation methods, so it seems likely that they are also used for internal trading. The picture above shows the dam for the upper reservoir at Ben Cruachan – I’d definitely recommend walking up to it if you are up that way!



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Why do negative electricity prices occur and can they encourage the use of inefficient energy storage devices?

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Negative electricity prices are a relatively recent phenomena in wholesale electricity markets. They were first seen in the German intra-day market in 2007 and are now rare but not extraordinary – there were 56 hours on 15 different days of negative electricity prices in the German day-ahead market in 2012. In modern wholesale electricity markets electricity prices are intended to and broadly do represent supply and demand, with a high price encouraging suppliers to participate in supplying electricity and a low price discouraging suppliers from producing electricity. Negative electricity prices mean that suppliers of electricity must pay consumers to use the electricity that they generate, rather than the usual manner in which consumers pay suppliers for the electricity they use. These negative prices generally arise when a highly inflexible electricity supply meets an exceptionally low demand and the supplier decides that the cost associated with the shutting down and restarting of the inflexible supply is more than the cost of paying an external party to use the generated electricity. Renewable output contributes to negative prices as there is often a protocol in place dictating that green electricity must be used ahead of other generation methods (for example coal and nuclear). Therefore when a time of exceptionally low demand coincides with a time of exceptionally high renewable output conventional base-load generation like nuclear could be asked to power down. A negative electricity price would then occur if the nuclear operator decided that it was cheaper to pay someone to use the nuclear energy generated at that time than to shut down (and subsequently have to re-start) the plant.

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Figure 1: Showing the increase in frequency of negative prices in some European electricity markets in 2013 compared to 2012.

What do negative electricity prices mean for energy storage?

Negative electricity prices indicate inflexibility, and their occurrence essentially reflects a need for energy storage. Their presence should encourage energy storage: instead of buying electricity and then selling it at a later time, storage can “sell” (be paid) taking electricity which can then be sold again at a later period. Of course the action of storage will oppose the prices negativity – storage will tend to push the prices up and a large enough capacity of energy storage should remove negative electricity prices. However apart from Pumped Hydro, energy storage devices are generally small-scale prototypes that are essentially “price-takers” in the market (their effect on the price is very small). These are devices currently being demonstrated and it is thus important to understand them fully in before much larger systems can be developed.

A negative electricity price essentially means that in the absence of any fixed storage operational costs it always beneficial for storage to charge on this negatively priced electricity irrespective of the sell price. By making the observation that an inefficient energy storage device will take more electricity to charge it than an efficient one, one important question is whether these negative electricity prices encourage the use of inefficient energy storage devices.

There appear to be two distinct methods by which energy storage can derive revenue with negative electricity prices. Firstly there the storage can charge at a negative electricity price and discharge at a later positive electricity price or secondly storage can charge at a negative electricity price and discharge at later negative electricity price. Initially I focus on the latter case. This may seem counter-intuitive but given two consecutive price periods with the same negative price the only storage system that will not make a profit by charging at the first and discharging at the second is a device that is 100% efficient (which will simply break even). Of course a more profitable single transaction would be charging at the negative price and discharging at a later positive electricity price, however charging and discharging using negatively priced electricity can still be profitable and will be more profitable the more inefficient the device is. Hence in a sustained period of negative electricity prices if there exists the opportunity for storage to make a complete a charge and discharge cycle before charging on negatively priced electricity and selling at a time with positive electricity prices then this will be the most profitable storage schedule. This represents an unlikely extreme case – it is obviously completely undesirable for storage to discharge at times of negative electricity prices but it is worth mentioning nonetheless. If sustained periods of negative electricity prices do start occurring then policy may need to step in to regulate storage behaviour.

The first method of charging on negatively priced and discharging at positive electricity prices is more intuitive. Generally it is anticipated that this should not encourage inefficient devices as a more efficient device with the same charging and discharging power would always be able to make more money on a single charging and discharging transaction. For example a device with a charging power of 1 MW could take 0.5MWh of electricity from the grid in a 30 minute period. A 75% efficient device would then be able to sell 0.375 MWh at a later positive electricity price while a 50% efficient device would only be able to sell 0.25 MWh. However, again the possibility of the less efficient device making a larger revenue comes with a sustained period of negative electricity prices. For example, consider two 2 MWh storage devices, one 100% efficient and one 50% efficient and each with a charging and discharging power of 2 MW (so in one half hour period 1 MWh can be taken from or exported to the local electricity network) and the price timeseries shown in Figure 1a and 1b. It is assumed that with a round trip efficiency of 50% the charging process and the discharging process each have an efficiency of 70.71%. Therefore only 70.71% of the energy used to charge is stored, and only 70.71% of the energy removed from the store can be sold.

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Figure 2: (a) Charging and discharging schedule for 1MW 2MWh 100% storage device. (b) Charging and discharging schedule for 1MW 2MWh 50% storage device. (c) Energy stored corresponding to Figure 1a. (d) Energy stored corresponding to Figure 1b.

As the Figure 1a and 1b show the 50% efficient device uses more energy to charge (the state of charge is shown in Figure 1c and 1d) than the 100% efficient device allowing it to exploit an extra period of negative electricity prices. The 100% efficient device then makes a greater revenue when discharging but not enough to make up for the extra negative electricity price period exploited by the inefficient device. With the price timeseries used the 50% device is able to generate an extra 6% revenue compared to the 100% efficient device.


To summarise, negative electricity prices indicate inflexibility in the energy network, and reflect a need for increased energy storage capacities. Energy storage devices should work to counteract these negative electricity prices by increasing demand and a large amount of energy storage should keep the electricity prices positive. However, given that negative electricity prices currently exist, there exists the possibility that these may encourage the use of inefficient energy storage devices that are better able to exploit these negative prices. This is not generally true and depends on the nature of the electricity prices – as well as the degree of positivity versus the negativity. However it is worth recognising the possibility that under certain circumstances negative prices can encourage the use of inefficient devices and this could be a hurdle in the development of effective energy storage techniques, especially given the small-scale demonstration nature of most current energy storage projects.