Jack of all trades: storage is being held back by its complex offering

From the archive: in the July 2015 issue of New Power Report we considered the state of play for storage. Have we made progress since?


Government and institutions are all keen on storage – but not yet. The story from new mechanisms like National Grid’s Demand Side Balancing Reserve and the Capacity Market are that they welcome bids from storage. But in practice, those mechanisms have largely incentivised traditional generation instead, some of it at small scale.

Poorly targeted mechanisms
Most industry support mechanisms are written on the assumption that the need will be met by large power stations. That bias generally makes it hard for storage – as well as demand side response or distributed generation – to offer into the market.
That’s not to say storage does not have government support – Decc invested over £30 million in 2013 and £5 million in 2015 in demonstration projects.  But there is a persistent feeling in some quarters that storage is “an option for the future” – as Ofgem’s Maxine Frerk described it at a meeting run by National Grid intended to drive interest in demand side response – rather than a market-ready option.
The Capacity Market (CM) is a case in point, where the mechanism’s structure does not work for storage.
The Electricity Storage Network detailed its concerns in 2013 when the CM was launched and little has changed.

The CM assumes that once called on, capacity can provide power continuously, but that is not the case with storage, which has a defined discharge time. That is a problem: when the CM calls on participants the amount of time that the alerts will apply is not known ahead of time, and may last for hours. If storage delivers power for a short period within that time it may miss the half-hourly periods when the stress event actually occurs (which is not determined until afterwards) so may even incur a penalty fro non-delivery.
In the next couple of years, when the CM uses transitional arrangements, the situation is slightly different. Storage can elect to offer capacity in specific windows – but the TA does not offer a long term contract.
Finally, storage has to be recharged after being called on in a CM event. That may be expensive – and not very beneficial to the system – if the system is still in a condition where power is scarce.
Frank Gordon, senior policy analyst at the Renewable Energy Association, says that contracts term is the broad issue. Storage might access diverse revenue schemes but, like the CM, they seldom offer the long term contracts that would make investment viable. “The longer the better,” he says, noting that Short Term Operating Reserve (Stor) contracts used to be available for a 15-year term. “It’s a long-term guaranteed income stream” that’s needed, he says.
Mick Barlow, application director with S&C Electric, agrees that it is the long term contract that “makes the business case” for investors. He also points to the onerous requirements for metering and certification that present a barrier to storage entering ancillary service markets. “Will [a company] go to all the effort [and cost] of putting in all the metering for one year?”
Barlow thinks there will be new options in a changing grid mix. There are new revenue streams.


Fault ride-through

One issue, as wind and PV penetration grows, is that the system has less “ride through”, and in the event of a fault frequency and voltage decays more rapidly than it did in the past. “Storage is an ideal response because it responds very quickly. And you have lots of flexibility – it can go from charging to discharging in milliseconds.” That’s much faster than diesel response, and diesel has other problems: “there is a minimum output, and also it becomes very fuel inefficient when operated out of its main range”.

Faster “ramp rates” is a pending problem that storage can solve”

Barlow says new products like enhanced frequency response and synthetic inertia respond to these new system needs. As the products are developed they should have storage in mind as an option.
He contrasts GB’s mechanisms with the simple way that one market in the USA, PJM, manages frequency response. “PJM created a reward for people who can follow a frequency signal more accurately. The more accurate you are, the better you are rewarded”. That fits well with storage capabilities. Small plant can participate – “S&C has a smart grid demonstration facility in Chicago and we put in 150kW, which is the minimum, to demonstrate it can work. It just follows the signal, making a bit of money as it goes”. A bigger installation would, of course, make more.
Barlow also picks “ramp rate” as a pending problem that storage can solve – and one where clear, stretching targets are important in building a market.  Fast ramping is already a management issue, especially for PV, which tends to come onto or off the grid very suddenly and all at once, as the sun rises or cloud cover changes. That presents stability issues.
This is a real issue in California, where the Public Utilities Commission has told utilities to contract for storage at all scale to help smooth the transition as power ramps up or down. Crucially, the PUC has set a target: “It has mandated that the three utilities contact for 1.3GW of storage over the next few years” Barlow says. Utilities are putting out tenders and have had hundreds of responses.

All in the algorithms
The question of how to manage several small revenue schemes is key to making storage work, and it is a complex one.
Phil Taylor, director of the Institute for Sustainability and professor of electrical power systems at Newcastle University, talks about how to make those work in practice.
Taylor sees an opportunity for storage in arbitrage – especially as negative prices begin to arise in some half-hourly periods. “If you look at PV and wind penetration the gap between minimum and maximum  prices is stretching”, he says.

Deferring capital cost in reinforcing or extending the network is another revenue source. But, “You either need a very large storage device or an aggregation, as in demand response. Research suggests it is most economic to have a mixture of demand response and storage.” He agrees that although storage is more expensive at the moment, its contribution will become more important.

For example, “Demand response is cheap but its weakness is being certain you will get the response. Overlaying storage will give you a nice shape,” he says.
But Taylor points out that using storage is at an early stage and researchers as well as analysts are grappling to model the complexity.

The difficulty is writing algorithms that give some forward view on how storage might act in the market, and then developing a risk management strategy that covers potentially multiple revenue streams. “How brave dare you be with the state of charge of the device? When, for how long, and what magnitude of charging would be best?” He suggests that at some periods or in some locations it would be better to keep the device at a low state of charge so you can earn from negative pricing – “you need to be able to absorb energy,” he says.

But for other revenue streams the device will be providing power and you want to be at a higher state of charge. “Trying to optimise that is a complex process,” he says. He is working with a group that is trying to develop algorithms that can bring together options in arbitrage, Stor, smoothing the output from wind farms and other options. The group is casting its net wide for examples to follow.

Telecoms networks provide good models, says Taylor, but, for example, “is it a bit like managing aeroplanes, are we assuming that people will cancel, so you oversell and take the penalty?” There is a shortage of data. And Taylor notes that the state of the installation is an important variable to add to the decision mix. “Every time you use a storage device you degrade it. [You need to understand for each use that] you age it by this much -  what’s the tradeoff against the battery lifetime?”

“How brave dare you be with the state of charge of the device? When, for how long, and what magnitude of charging would be best?”

When it comes to technologies, Taylor says there is plenty to choose from – and that’s part of the problem in reducing costs. “For very fast short term reserve you would use supercapacitors – they are very fast but they can’t store much. If you are chopping every peak that’s a lot of energy so you need lithium ion batteries. There’s not one technology that wins [every time].”

Technology choices
At the moment the lithium ion industry is scaling up and “everyone is hoping that the automotive industry will drive prices down,” Taylor says. In an ideal world that’s not the right choice for grid applications  – a materials scientist would say that the lifetime, cycling and energy density characteristics are not ideal.  “In a vehicle the battery needs to be light and small,” Taylor says, which is not necessary in grid applications, and “you are paying for the density and the [light] weight”.
But even if that’s not exactly the right technology the lithium ion boom may help the storage industry take its place in the network.  It’s simple to scale up – the largest batteries like UKPN’s in Leighton Buzzard simply stack thousands of small units to achieve the right capacity. And some of the cost of installation are outside the battery – control technologies, inverters, etc. That part of the installation also has to move down the cost curve over the coming years and that means it needs to be
It may be that lithium ion is a transitional technology. That may be beneficial, allowing storage to take its place in the network now and allowing the battery “core” to be replaced by other, cheaper, technologies as part of a regular replacement cycle.

Behind the meter, and BOO
REA’s Frank Gordon casts another interesting light on storage potential. That’s using it on the customer side – “behind the meter”. It’s one way of using storage that makes savings for the user. It can cut Triad payments, for example, or be brought into operation to cut power imports during “red band” periods when distribution use of system (DUoS) charges multiply.

It’s an option for large industrial and commercial users who see and can manage those cost elements in their bills. Such companies may also be offering STOR and other services.
It may be that business customers are one group that can bring together the diverse revenue streams for storage, although it should be recalled that large customers often require very fast payback for this type of investment – within a couple of years, which could be impossible for storage at this stage of development. Business customers are often the target for  energy measures like demand side response, and although they often have knowledgeable energy buyers, their activities are always in service to the company’s main business – which is producing products, not providing energy.
How many companies might look at storage? That could be impossible to tell: unless they are offering direct contracts and some control, companies’ activities “behind the meter” are largely invisible to the wider electricity network, both to DNOs and to National Grid.
Finally, Gordon suggests there may be other financing opportunities.

In practice, some existing battery applications, even automotive, involve long-term leasing arrangements for the battery itself. That raises two interesting possibilities: one a second hand battery market using partially degraded batteries in less critical applications, which may help reducing life cycle costs. The other is the type of financial structure sometimes seen elsewhere in the power sector. “We haven’t seen ‘build, own operate’ (BOO), or ‘build, operate maintain’ (BOM) offers in the market yet,” says Gordon. But we might.


More on storage

Joint action needed on market frameworks

It’s energy, not just gas, that we must store

Further reading for subscribers:

Interview: Professor Phil Taylor, Newcastle University

Interview: Jill Cainey, Electricity Storage Network

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