Category Archives: Energy storage economics

CAES: A simple idea but a difficult practice

 

Compressed Air Energy Storage: A simple idea but a difficult practice. (228 downloads) .

In the mainstream there are two main branches of Compressed Air Energy Storage (CAES) – conventional and adiabatic.

  1. Conventional CAES

Conventional (also known as diabatic) CAES plants are essentially gas turbines in which air is pre-compressed using off-peak electricity, rather than running a turbine and compressor simultaneously. In these plants, off-peak grid electricity is used to compress air which is stored, and then mixed with natural gas and combusted during expansion. Compression is staged and the majority of the compression heat wasted (although some may be stored in a recuperator to pre-heat the air before combustion). Currently there are two commercial CAES plants worldwide; the Huntorf plant in Germany and the McIntosh plant in Alabama.

  • Huntorf CAES plant: Data from [1]. 310,000m3 cavern at a depth of 600m, pressure tolerance between 50 – 70 bar, converted from a solution mined salt dome. Daily charging cycle of 8h, output of 290MW for 2 hours. 0.8kWh of electricity and 1.6kWh of gas required to produce 1kWh of electricity. Notably, built when the price of gas turbines was historically high.
  • McIntosh CAES plant: Data from [2]. 538,000m3 salt cavern at a depth of 450m, pressure tolerance between 45-76 bar. Originally it provided an output of 110MW for 26 hours but in 1998 two extra generators were added and its total output capacity is now 226MW. 0.69kWh of electricity and 1.17kWh of gas to produce 1kWh of electricity.

Both plants are commercially viable and still running in their respective markets!

CAES

Figure 1: Schematic of diabatic CAES system.

As with Pumped Hydro Storage (PHS), CAES also requires favourable geography to provide the underground air storage caverns. However there are many more suitable sites worldwide than for PHS, although the costs are highly site specific. The costs of mining a suitable underground cavern where suitable geology doesn’t exist or creating an above-ground equivalent storage container are potentially prohibitive, whereas alternatively a naturally occurring cavern or somewhere easily minable may offer a very attractive price of storage in terms of $/kWh (or dollars per metre cubed of air storage).

Caverns can be created in salt geology (typically using salt solution mining techniques) or existing caverns can be exploited provided that they are capable of housing the desired pressure. Geological formations such as aquifers and salt formations (bedded salt and domal salt) offer potential locations. Costs can also be reduced if existing well infrastructure is in place from previous underground drilling operations. While specific geology is required, this geology is relatively widespread. For example, the EPRI suggests that up to 80% of the US could have favourable geology [3] (see Figure 2).

US CAES map with wind resources marked

Figure 2: US geology for compressed air caverns. Regions with high wind resources are also indicated with the idea that CAES sites and wind turbines could be co-located [4].

Estimates for the costs of cavern mining can be as low as $1/kWh of storage capacity if solution mining techniques can be used [5]. In solution mining, fresh water is pumped in a salt deposit, becomes saturated with salt and is then removed. One problem however is that disposal of this brine can cause environmental issues.

1.1 CAES Performance Characteristics and Applications

CAES systems have traditionally been designed as centralised storage facilities which are intended to cycle on a daily basis and to operate efficiently during partial load conditions. This design approach allows CAES units to swing quickly from generation to compression modes and means that they are well suited to ancillary services markets, providing frequency regulation. Their ability to operate on a (intra) daily cycles means that they are also useful for load-following/peak shaving. The air storage caverns can also be very large, allowing for multiple days worth of electricity storage.

It should be noted that the inlet pressure (45-76 bar) for the CAES high pressure turbine is much higher than the equivalent for a typical gas turbine (about 11 bar) so a typical gas turbine can only be used as the low pressure expander. The high pressure turbine at Huntorf is based on a small-intermediate steam turbine design.

1.2 Table of Cost Estimates

Typical Capacity Typical Power Efficiency Storage Duration $/kWh $/kW Lifespan Cycling capacity
500MWh – 2.5GWh 50 – 300MW n/a Hours – days 4-7 [6], 2-50 [7], 60  – 120 [8] 300-600 [6], 400-800 [7], 1000-1250 [8] 20-40 years High

Table 1: CAES cost characteristics

 

  1. Adiabatic CAES

Adiabatic CAES is an energy storage concept that removes the natural gas combustion from conventional diabatic CAES. In adiabatic CAES the heat generated by the compression of air (the charging process) is stored in a Thermal Energy Store (TES) which is separate from the ambient temperature high pressure air store. When the system is discharged the high pressure air is reheated using this stored heat and then expanded. Without the stored heat, the process has an unacceptably low efficiency – this is because significant exergy is stored in the heat as well as the cool high pressure air. When the heat is recovered, the expected practical efficiency of these systems is debated – though the second law of thermodynamics does not pose a ceiling on the efficiency as for  heat engine – it just means that the real process has to be less than 100% efficient. Pragmatic estimates of the real efficiencies of this type of system are debated; most of the academic literature estimates practical efficiencies in the range of 60-75% [9,10]. If a plant could be constructed with no inefficiencies in any process – the theoretical efficiency would approach 100%.

2.1 Status

As no demonstration plant has ever been successfully constructed, Adiabatic CAES must be considered as an unproven technology. It does however have significant promise for use with renewables integration, energy management, peak shaving and grid reserves. The largest planned demonstration ACAES facility is a 290 MW adiabatic CAES project based in Germany called project ADELE [11]. It is a consortium between German utilities RWE and GE, the German Aerospace Center DLR, construction company Zublin, the Fraunhofer IOSB and the Unversity of Magdeburg.

Adiabatic CAES

Figure 3: A simple schematic of an ACAES configuration. There is a thermal store for each compression stage.

A schematic diagram of an ACAES system is shown Figure 3. In this configuration, air is compressed and then cooled using counter-current heat exchangers that transfer the heat from the air into a thermal fluid. This thermal fluid could then be stored in an insulated tank and used to reheat the air prior to each expansion stage. Several people have also suggested the use of Packed Bed regenerators to store the compression heat in the air.

2.2 Underwater CAES

Underwater CAES is a sub-type of ACAES which exploits an underwater Compressed Air Store at a depth of typically around 400m. The ambient pressure at this depth is approximately 40 times the atmospheric pressure, and the air store is either a flexible bag or a dome structure open at the bottom. As air is pumped into the storage container it displaces water and thus the store can operate at a constant pressure. This idea was pioneered by Prof Seamus Garvey and Dr Andrew Pimm at the University of Nottingham, as well as by researchers at the University of Windsor Ontario and Canadian startup Hydrostor (whose work is ongoing at the time of writing).

2.3 Fuelless CAES

The usage of the term “adiabatic CAES” is also somewhat ambiguous, as the term “adiabatic” is sometimes used to refer to the compressions and sometimes to refer to the overall process – i.e. the energy storage process aims to be adiabatic in the sense that ideally, it would exchange negligible heat with the surroundings. Therefore some authors therefore prefer the use of the umbrella term Fuelless CAES. This then clearly encompasses all compressed air processes which aim to store and return energy without the use of fossil fuels. This includes systems which have typically been labelled as isothermal CAES.

2.4 Isothermal CAES

In isothermal CAES the compressions aim to be isothermal and reversible. This is theoretically achieved by minimising the temperature differences which drive heat flow from the compressors to the environment (which is at a lower temperature). A huge challenge here is to make an isothermal compression process which operates sufficiently quickly to be of practical industrial importance but which is still slow enough to maintain the small temperature differences required for high reversibility. One idea for near-isothermal compression which has been suggested by LightSail (a start-up company in California) involves a water spray into the compression chamber of a specially designed reciprocating compressor/expander unit (see Figure 4). The water droplets absorb the heat of compression and their high specific heat capacity causes the temperature increase in the compression chamber to be much smaller. This warm water is then stored and on discharge is re-injected as a mist into the reciprocating machine which now acts as an expander.

Figure 4: Illustrating a near-isothermal CAES concept [12]

Isothermal CAES was also being pioneered by SustainX, however this company has ceased operations citing spiralling system costs. Lightsail Energy and SustainX had a similar goal of an efficiency above 60% for their first generation of machines and believe that 75% is achievable in the long term. The SustainX prototype was a 1.5 MW machine.

2.5 ACAES Challenges

There are several challenges which must be overcome before adiabatic CAES can become a viable energy storage technology option.

  • Specialised compressor equipment must be developed, in which the heat generated during the compression procedure is stored in a highly reversible manner. This process seems most likely to consist of a series of adiabatic compressions in which heat losses from the compressor to the surroundings are minimised. The compressors must also operate with much higher compression ratios than current compressors which do not involve cooling during the compression. Each of the compressions is then followed by a cooling stage which aims to reversibly extract the compression heat. Possible options for heat extraction include packed bed regenerators or counter-current indirect contact air-to-fluid heat exchangers. This type of compression equipment is fundamentally different to industrial many industrial compressors. Why? Because the vast majority of compressors are designed to minimise the work required to achieve air at a given pressure. Most industrial compressions then typically involve trying to shed as much heat as possible from the compression process – as hot air takes more work to compress. The ACAES process is fundamentally different as reversibility should be maximised rather than work minimised. In fact, the greater the reversible work is per cubic metre of compressed air the higher the energy density of the storage system.
  • Specialised expansion equipment must also be developed. Air turbines which provide highly isentropic expansions and operate within the desired pressure ratios are required. The expansion process of an Adiabatic CAES system should aim to mirror as closely as possible the reverse compression process. Therefore it should include the same number of expansion stages and heating stages, and expansion stages must aim to minimise heat gain and return all heat reversibly during the heating stages. While these turbines do not currently exist on the industrial market, it is anticipated that their design can learn much from the current generation of gas turbines for power generation. The pressure ratios will likely be smaller than most current gas turbines. One specific advantage is that the material demands will be much less (in terms of temperature tolerance) than current gas turbines which operate with inlet temperatures up to 2200K.
  • Sliding pressures. Unless the system can be operated between constant operational pressures, both the compression and expansion machinery must operate at maximum efficiency over a range of pressure ratios. A single constant high pressure air storage is a primary advantage of UnderWater CAES.
  • High pressure air storage. Depending on the chosen method of storage high pressure, air storage tanks must be developed which have minimum cost. This has apparently been a problem area both for SustainX and LightSail, however LightSail have released statements which hint that they may have found a method of lowering the costs.
  • highly reversible heat exchangers will also be required which can minimise the temperature difference between the working fluid and the thermal storage medium while introducing minimal pressure drops.

2.6 Notable experimental ACAES development

Lightsail (California) – startup. http://www.lightsail.com/

Hydrostor (Ontario) – startup. https://hydrostor.ca/

SustainX (Massachusetts) – startup (liquidated)

Project Adele (Ongoing utility/academic collaboration – big unexplained delays??)

University of Windsor – Prof. Rupp Carriveau and Dr. David Ting

University of Nottingham – Prof Seamus Garvey and Dr Andrew Pimm

 

 

 

 

References

[1] BBC Brown Boveri. Huntorf Air Storage Gas turbine Power Plant. https://www.eon.com/content/dam/eon-content-pool/eon/company-asset-finder/asset-profiles/shared-ekk/BBC_Huntorf_engl.pdf

[2] M. Nakhamkin, L. Andersson, E. Swensen, J. Howard, R. Meyer, R. Schainker, R. Pollak, and B. Mehta, J. Eng. Gas Turbines Power 114, 695 (1992). https://doi.org/10.1115/1.2906644

[3] Compressed Air Energy Storage: Renewable Energy (2010, March 17) retrieved 22 April 2017 from https://phys.org/news/2010-03-compressed-air-energy-storage-renewable.html

[4] Succar, S & Williams, R.H.. Compressed Air Energy Storage: Theory, Resources, and Applications for Wind Power, Princeton University (published April 8, 2008)

[5] De Samaniego Steta, F. Modeling of an Advanced Adiabatic Compressed Air Energy Storage (AA-CAES) Unit and an Optimal Model-based Operation Strategy for its Integration into Power Markets. EEH – Power Systems Laboratory. Swiss Federal Institute of Technology (ETH) Zurich

[6] Kaldellis, J. K. & Zafirakis, D., 2007. Optimum energy storage techniques for the improvement of renewable energy sources-based electricity generation economic efficiency.. Energy, Volume 32, p. 2295–2305.

[7] Chen, H. et al., 2009. Progress in electrical energy storage system: A critical review. Progress in Natural Science, Volume 19, pp. 291-312.

[8] EPRI, 2010. Electricity Energy Storage Technology Options. http://large.stanford.edu/courses/2012/ph240/doshay1/docs/EPRI.pdf

[9] G. Grazzini, A. Milazzo. A Thermodynamic Analysis of Multistage Adiabatic CAES. Proc IEEE, 100 (2) (2012), pp. 461–472

[10] Barbour, E, Mignard, D, Ding, Y,  Li, Y. Adiabatic Compressed Air Energy Storage with packed bed thermal energy storage, Applied Energy, Volume 155, 1 October 2015

[11] RWE Power. ADELE – Adiabatic Compressed Air Energy Storage for Electricity Supply. https://www.rwe.com/web/cms/mediablob/en/391748/data/364260/1/rwe-power-ag/innovations/Brochure-ADELE.pdf

[12] Fong, D. Insights by Danielle Fong. https://daniellefong.com/

 

 

 

A new high in renewable electricity for Germany – and a low in electricity prices!

On Sunday 8th May Germany hit a new high for electricity generation from renewables, with renewable plants supplying 87% of the demand. The result was several hours of negative electricity prices – to such an extent that commercial electricity consumers operating through the wholesale market were paid to consume electricity. This has been reported by articles in Quartz and The Independent.

German consumption, renewable energy supply, conventional supply and prices for 7/8 May 2016

German consumption, renewable energy supply, conventional supply and prices for 7/8 May 2016. Figure from Quartz article.

As I reported in an earlier blog post, negative electricity prices are generally a reflection of insufficient flexibility in the power network. In the case of Germany on the 8th of May 2016, negative prices occurred due to a combination of high wind and solar production, and low energy consumption (due to it being a Sunday). Accordingly, there was significantly more electrical supply than demand and the electricity prices were negative from 7am – 5pm. It is interesting to note from the Figure (taken from the Quartz post) that there doesn’t seem to be a huge difference between the conventional production on Saturday compared to that on Sunday, but this small increase in the ratio of renewable to conventional power resulted in a hugely negative price spike. Additionally we also see that on both days the production was higher than consumption – I assume that this is a reflection of German exports to other electricity markets. It only seems likely that as Germany strives for 100% renewable electricity this type of situation will occur more and more frequently and will make the situation for storage more favourable. It would be ironic if the low daytime electricity prices that have eroded the market for energy storage in Germany could become so low that they actually began to favour storage again.

Also, for interest, an article I wrote about negative electricity prices and energy storage.

 

Storage and the duck

The California duck curve is now infamous and is very often features in discussions around storage. The duck phenomenon is a result of several factors coming together at once to create a scenario in which there is significant strain on the electricity generation system.

The infamous California duck

The now infamous California duck.

Typically the output from solar panels is well-aligned with times of high electrical demand, especially in systems which have large cooling dominated loads. This is because it often gets hot when the sun is shining and people tend to be most active during the daylight hours.

Solar generation typically occurs when demand for electricity is high - during the middle of the day.

Solar generation typically occurs when demand for electricity is high – during the middle of the day.

However when there is a cool sunny day in systems which have a lot of solar panels that are typically used to meet cooling-driven loads, then the situation can arise in which the net demand for electricity which must be generated by conventional powerplants (i.e. coal, nuclear, gas) becomes depressed, as most of the demand can be met by the solar. This is a problem for utilities in itself as turning down the output on some of these plants (especially nuclear, to a lesser extent coal) is difficult and costly, so instead they sometimes opt to sell their electricity very cheaply (or even pay for it to be used when prices go negative). For utility-scale renewables this is also a problem, as they can end up in the situation where they simply have to stop producing electricity. On top of this, the power output from all the solar panels in a local region is very well correlated. Therefore they all start and stop producing power at close to the same time (there is some spread due to orientation and location). This leads to a sharp increase in the net demand leading up to the evening peak which typically occurs after the sun goes down. There are only certain types of plant which can react to changes in demand quickly (they have high ramp rates), for example gas and hydro and only hydro can do it cheaply, as conventional gas plants must already be running for some time at their Minimum Stable Generation levels before ‘ramping up’, which is often less economic and more polluting per unit of electrical output.

Solar Panel outputs from the Pecan Street project (https://dataport.pecanstreet.org/)

Solar Panel outputs from the Pecan Street project (https://dataport.pecanstreet.org/) all producing electricity at the same time. Red line is the average

The concern about the duck is a prime driver for energy storage development. This storage can come in several forms – i.e. not just batteries coupled with the solar panels. Some of these are highlighted in this NPR discussion which includes fuelless Compressed Air Energy Storage, Concentrated Solar Power with thermal storage in Molten Salts and Ice Storage for cooling.

Ultimately it is all down to the economics. If the costs of storage are less than the increased costs of utilities as a result of having to provide the additional flexibility the duck requires, or if storage can increase the value of renewable energy sufficiently then it will become a viable option. At present the costs of curtailment are likely to be less than storage, but as the amount of curtailment increases and storage costs fall then this could rapidly change.

Capacity markets and energy storage

I’ve been meaning to get my thoughts together about capacity markets and energy storage ever since the inaugural UK capacity market last year. So here it is, I start by talking about what a capacity market is and aims to do and then think about how it can affect energy storage economics.

The purpose of a capacity market is to ensure that there will be enough powerplants installed and available to generate (sufficient generating margin) for the future operations of an electricity system. The capacity market aims to do this by providing stable and regular payments to market participants who agree to guarantee capacity which can be used to meet peak demand at some point in the future, over and above the payment they receive for the energy that they sell.

Historically the electricity industries in most countries were developed as government owned monopolies. One of the legacies of this is that the wholesale price paid for electrical energy in today’s restructured markets doesn’t usually include the cost of building the powerplants themselves. Although in today’s restructured, re-regulated (liberalised) markets the costs of electricity are nearly always much higher than the marginal production cost (due to a number of factors including utilities’ market power), often these costs are not high enough to justify investments in new powerplants. This is known as the ‘missing money’ problem in electricity markets.  Because electricity demand is so variable, and the highest peak demand only covers a short time span and occurs infrequently, electricity systems often have more than sufficient capacity for normal demand levels but insufficient capacity to reliably cover the highest peak demand spikes. If electricity were a more normal commodity, at times of high demand, high electricity prices would cause some consumers to decide they didn’t want to buy electricity, which in turn would cause the demand to fall. The ‘market price’ reached in this situation may then persuade other potential generator operators to enter the market (by building new powerplants). However as the majority of consumers do not see and thus cannot respond to real-time electricity prices, during times of power scarcity, administrative controls often limit the market price to stop it becoming unreasonably high – the demand for electricity is very inelastic. The missing money problem then occurs when the market prices are limited by administrative actions such as price caps. This means that large potential rewards to generators are forgone, and this can in turn result in little investment in new plants which would provide electricity during these times of scarcity.

In an attempt to get around this issue, the capacity market then provides supplementary income to powerplants, in addition to what they earn in the energy market, to cover the costs of ensuring that they are available to generate in future. Capacity (in kW per year) is traded in the capacity market while wholesale electricity (in kWh) is traded in the energy market. The capacity payments are received by the capacity providers in the relevant delivery year and are typically paid for by a charge levied on all electricity suppliers (which in turn is passed on to consumers). There are also penalties for failure to meet a provider’s agreed capacity.

Capacity markets usually include a large primary auction at some specified interval (4 years in the UK) before real time followed by smaller incremental auctions at closer time(s). The price paid for all the accepted bids is the market clearing price – representing the price of the most expensive unit of capacity required. This is known as pay-as-clear. It aims to encourage plants to bid in at their actual marginal cost, rather than speculating what the market price may be. The plant with the lowest marginal cost should then make the largest profit as all the capacity providers receive the same payment. Figure 1 illustrates how the capacity market bids are evaluated.

Illustrating how the "pay-as-clear" capacity market auction works. The red line illustrates the target capacity. All bids below this are accepted and paid the price of the last kW of capacity.

Illustrating how the “pay-as-clear” capacity market auction works. The red line illustrates the target capacity. All bids below this are accepted and paid the price of the last kW of capacity. Source the energy collective.

One big risk with capacity markets is that they rely on accurately forecasting future demand levels, to determine the optimal level of capacity in future years. If future demand levels are over-predicted, this can result in a large oversupply of capacity and uneconomic plant retirements, burdening consumers with very high costs for reliability. This has happened in Western Australia.

The inaugural UK capacity market was run in 2014 to secure capacity for the winter peak season 2018-19. This is a T-4 auction (four years ahead of delivery) and there will also be a T-1 auction. Capacity providers are free to adjust their positions in private markets from one year ahead of the delivery year and throughout the delivery year, subject to some restrictions. The capacity providers must then be prepared to provide capacity when the system operator issues a capacity market warning. The market rules state that the “System Operator will issue a Capacity Market Warning (CMW) when the anticipated system margin in four hours’ time is less than 500MW. In the event of a System Stress Event starting which was not forecast, a CMW will also be issued. The CMW remains inforce until the forecast available margin is greater than the trigger level of 500MW.” Once the CMW is issued, providers must deliver their capacity obligation in four hours’ time to avoid CM penalties, should a System Stress Event be active at that time.

Where does energy storage fit into capacity markets?

Capacity markets are often touted as a good potential way for energy storage operators to gain revenue, which when combined with revenues from the energy market, could be sufficient to encourage investment. It has often been observed that the rewards open to energy storage devices in energy-only markets are generally not sufficient (certainly not at present) to justify investment in storage technologies, and the extra income from capacity markets is designed to justify investment in new infrastructure (i.e. generation or storage). Importantly, not only for storage but for all capital-intensive electrical infrastructure, the payments for providing capacity also have the advantage that they represent a reliable source of future income.

However in order to justify investment in new technologies like energy storage, the price reached in the capacity auction must be high enough, and if the price is to reach these high levels then either the level of required capacity must be set high by the system operator (the auctioneer), or some existing resources should not be allowed to enter into the market. Last year, the UK held its inaugural capacity market auction. The auction aimed to be “technology neutral” and nearly all existing generating resources were able to compete, including storage and demand response. The providers were only evaluated at their bid price rather than any other factors, for instance, emissions. The result of this was a price of £19/kW which was too low to for any new energy storage projects.

The real winners of the auction were the incumbent large utilities, whose existing plants got most of the capacity. These plants will be paid the result of the capacity auction on top of what they already earn in the energy market, provided they are still available to operate in the delivery year. This has frustrated many people as it is highly unlikely that many of these plants wouldn’t have generated anyway, so the net outcome of last year’s UK capacity market seems to have just been a significant increase in consumers’ electricity prices for the services they were already getting. What many people see as a problem is that the capacity market did not take into account any environmental factors that would remove, say, coal generation from the auction. DECC had originally stated that nuclear and coal would not be allowed to participate in the capacity auction, but after lobbying from the industry, changed this position.

It seems likely that if capacity markets are to be truly relevant to energy storage, then these markets will have to take into environmental factors like emissions into account. It is fairly obvious that in the short term the costs of meeting our capacity needs are lowest with fossil fuels, however it is the long term cost on society and the environment that these markets should aim to minimise. If we believe in decarbonisation then existing coal plants in particular should not be competing for new capacity payments. In order to encourage storage or other new low-carbon technologies, capacity markets should be further in advance and more ambitious – they should only be open to technologies whose emission levels comply with our decarbonisation targets.

The results of the inaugural UK market imply that the current UK government is much more concerned with security of supply than decarbonisation (although many sceptics say that security of supply has decreased due to our extended dependence on fossil fuels and the result of the auction will be an increase in electricity bills of £1 billion for the same service). Undoubtedly, security of supply is important, but it is, at best, overly-pessimistic to think that security of supply cannot be achieved simultaneously with decarbonisation. An ambitious capacity market would seek to address both of these challenges. Smaller capacity auctions with ambitious environmental targets and higher rewards that look further into the future may be one way to simultaneously achieve both of these aims. In this way these markets could drive up innovation in renewable-storage projects.

 

 

Tesla enters residential battery market with the Powerwall

The big storage news of the week has been the unveiling of Tesla’s new stationary energy storage battery project – the Powerwall. This has inspired me to think a little out-loud about the economics of residential batteries…

Tesla battery

The Tesla powerwall: could it become the iphone of residential batteries?

The powerwalls units come in two sizes, 7 kWh and 10 kWh and cost $3000 and $3500 respectively.

Tesla gives the specs as follows:

  • Mounting: Wall Mounted Indoor/Outdoor
  • Inverter: Pairs with growing list of inverters
  • Energy: 7 kWh or 10 kWh
  • Continuous Power: 2 kW
  • Peak Power: 3.3 kW
  • Round Trip Efficiency: >92%
  • Operating Temperature Range: -20C (-4F) to 43C (110F)
  • Warranty: 10 years
  • Dimensions: H: 1300mm W: 860mm D:180mm

Firstly it should be noted that the costs are wholesale costs, and don’t include the price markup – ignore this for the moment. Secondly, and more importantly, you need an inverter, so let’s conservatively add $1500 on to the capital of the battery. So for a 7 kWh system let’s say $4500.

So what can you do with 7 kWh?

The average UK house used about 4200 kWh of electricity in 2013, giving an average demand of very roughly 500 kW (4200 kWh divided by 8760 hours in the year). This equates to around 14 hours of power at this average usage. Of course, sometimes you are asleep or out, so let’s assume that when you are in the average demand is double this at 1 kW (about the power of a medium kettle). Here is a page with estimates of the average power for household appliances in 2008 (they may have got marginally more efficient). So you can probably expect to run your dishwasher and washer in the evening and you’ll have enough juice for lights and TV watching, but you’ll struggle to tumble-dry your clothes too. The peak power is also slightly limiting – you may struggle to run your electric shower, dishwasher and washing machine at the same time.

You would have to be a very frugal user of electricity to consider going off-grid with this battery.

Economics (in UK context)

So how does it stack up economically? Well, obvious things first, you aren’t going to get a saving even if the battery is free unless the price of your electricity varies with time – for example with a time-of-use tariff or if you have your own solar installation that has a different cost associated with the electricity it generates.

Working with a solar PV installation

Let’s say the cost of a solar installation in the UK is roughly £4000 for a 2 kW system, and this produces roughly 2000 kWh per year (that’s about half the yearly average demand for a UK household and equates to roughly 40 kWh a week). Let’s also assume that you get a generation Feed in Tariff of 13.4 p/kWh and an export tariff of 4.8 p/kWh (you get paid 13.4 p/kWh of electricity that you use and 4.8p/kWh of electricity you export), and the price you pay for your grid electricity is 15 p/kWh. Again, if you are using all the solar electricity you generate rather than exporting it, then there isn’t going to be any economic case for a battery. But if you are exporting some to the grid then by storing it you’ll be able to earn the generation tariff and displace the cost of some grid electricity later, but you’ll forfeit any earnings from the export tariff. So, if the round-trip efficiency of the battery is 85% (Tesla say 92% but this will degrade over time so we assume 85% as an average and there will be small losses associated with the inverter), you’ll get an extra 13.4 p/kWh plus 0.85 X 15 p/kWh minus 4.8 p/kWh = 21.35 p/kWh for the electricity you would have exported. Using all of these estimates we conclude that if you exported 50% of the electricity generated by your solar unit, you could save 1000 kWh X 21.35 p/kWh = a princely sum of £214 per year.

Of course this assumes that the battery has sufficient capacity to store all the electricity that would have otherwise been exported to the grid. 1000 kWh per year is approx. 3 kWh per day and the battery holds 7 kWh, but there is also a huge variation in the daily electricity generated, accounting for seasonal and weather-related variations. But for simplicity let’s assume that out 7 kWh battery can hold all the electricity generated. Approximately then, over the course of 10 years you may be able to save about £2000 using the battery. This is approx. 2/3 the cost of the battery. The figure below shows the expected yearly saving against the percentage of electricity exported by the solar PV system. It also shows the saving associated with the standalone solar PV system.

Saving capability of battery (blue line) against percentage of solar electricity exported (assuming battery always has sufficient energy capacity) - the dotted line shows how I would expect this to vary accounting for the finite capacity of the battery. Estimated saving from 2 kW PV installation also shown (green line)

Saving capability of battery (blue line) against percentage of solar electricity exported (assuming battery always has sufficient energy capacity) – the dotted line shows how I would expect this to vary accounting for the finite capacity of the battery. Estimated saving from 2 kW PV installation also shown (green line)

At 50% electricity export our standalone solar PV system gives us a yearly saving 1000 kWh X (15 p/kWh + 13.4 p/kWh) + 1000 kWh X 4.8 p/kWh = £332. Very approximately that yields a payback of 12 years, which isn’t too far off other estimates (usually around 10 years). The battery-plus-solar system increases the yearly saving to a maximum of ~£500 (with 50% electricity export) and increases the whole system payback in excess of 14 years. Including the inability of the battery to store all the energy exported on summer days I’d expect this to realistically be significantly in excess of 16 years.

Storage and variable grid electricity prices?

The other way electricity storage lets you save is by buying low cost electricity, storing it, and using it when you would otherwise have to buy high cost electricity. Most domestic customers in the UK aren’t on variable tariffs but as an academic exercise let’s consider an Economy 7 tariff, which gives 7 hours (12am – 7 am) at 8 p/kWh and 17 hours at 16 p/kWh (I think these numbers are reasonable estimates). Working at around 80% depth-of-discharge, the battery could displace 5.6 kWh of peak electricity, replacing it with 6.6 kWh of off-peak electricity. If this strategy was run 5 days a week for 52 weeks, then it could generate a saving of around £100 per year. This is a bit less than half of the saving associated with the battery-solar system.

It says quite a lot about the economics to note that at 16 p/kWh, the value of the electricity stored in the battery is ~£1.10. At 3000 cycles this equates to a value of £3300.

Using UK spot market prices from 2013 we find that the 7 kWh battery could have made a maximum of £65 from (wholesale) electricity arbitrage in the year 2013 (to calculate this I use MATLAB and an algorithm available here).

Do combined solar-battery systems reduce the net emissions of the electricity grid?

This is more tricky. Any energy storage device is a net consumer of electricity. From that perspective, unless the electricity would otherwise be wasted it’s better to use it rather than store it. So if you are exporting electricity to the grid and the transport process (to where that electrical energy is used) is more efficient than your round-trip storage efficiency, then storing this electricity instead will increase the global net electricity used. To understand the effect on emissions you’ll need to know what generation source the exported electricity would displace and what generation source the stored electricity would displace. Several other factors also contribute – the battery will contribute to grid reliability and thus reduce the operating reserve margin. If there isn’t much solar in the region then it’s likely that the reserve margins will remain unchanged, however with enough distributed renewable generation at some point another thermal plant will need to be brought online (to deal with the extra fluctuations in supply and demand associated with many distributed renewable generators). In this way, as more and more distributed generation (i.e. residential solar PV) is brought online then storage becomes more important for the grid and is likely to reduce emissions through a meaningful contribution to reliability.

What should be concluded from all of this?

Well firstly it should be pointed out that what Tesla is doing isn’t new – solar plus storage has been done for quite a long time. Traditionally Lead Acid batteries were used, and they still have lower capital costs but are bulkier, require maintenance to replenish the electrolyte and vent hydrogen gas during charge. There are also other residential Lithium ion battery systems out there. Having said that, what this move represents is a big, exciting & fashionable company throwing its weight into the residential storage market. Tesla has the potential to become the iphone of residential batteries.

In terms of the UK economics, the battery and solar option isn’t going to be more economical than using grid electricity. With the current subsidy levels, and given that our estimated system costs are probably on the low-side, I’d imagine that payback for a battery-plus-solar-PV system is in excess of 15 years at present. This is compared to a payback around 10 years for a standalone PV system. The economic case for based on variable prices is much weaker than the case for solar-plus-storage – we anticipate a max saving less than £100 per year.

In other countries I would expect a similar situation, however in regions where outages are more common, the batteries may add an Uninterruptible Power Supply (UPS) which could drastically increase its value. Though it should be noted that in these areas batteries are already used, and if these are lead-acid type batteries then they will be significantly cheaper. For UPS applications efficiency and cycling are much less important so it’s hard to see the Tesla batteries becoming a better option.

For people who want to use the battery to reduce global net carbon emissions then you’ll need to carefully construct your arguments on why you think this is the case. There are lots of inter-playing effects that, as discussed, can lead to an increase or decrease in global net CO2 emissions. In the UK at present, the grid’s CO2 emissions are fairly consistent at about 500 g CO2 per kWhel­ when the demand is above 25 GW, so it’s hard to imagine that battery use would do anything but lead to a net increase in emissions at the minute in the UK.

However, if you would like to be more independent of the grid, or take a big step towards what many experts believe is a likely possibility for a low-carbon future, and own what could be turn out to be a very fashionable product then this could be the battery for you.

China up to second for installed capacity of Pumped Hydro

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.

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

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 US DOE energy storage database. Available in text format here or from the downloads page.

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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.

Business models for energy storage

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.

energy storage business modelHow 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.

 

Pumped Hydro

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!

Negative electricity prices and storage – perhaps not just an academic curiousity

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

What are negative electricity prices and how do they occur?

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.

Negative electricity prices and storage

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.

storage schedule 50 per cent storage schedule 100 per cent state of charge 50 per cent state of charge 100 per cent

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.

Summary

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.