Surely it’s a simple thing to categorise electricity storage? Think again. Under UK market definitions constructed to accommodate generators and suppliers – storage is neither supply nor generation. Or else it is both.

Meanwhile, there is certainty in some quarters that storage is needed as a matter of urgency to compensate for the intermittency of renewable power. Stakeholders from across the energy sector share an ambition to add 2GW of storage capacity to the UK’s current 3GW by 2020. The technologies closest to commercial operation include various batteries at the low to middle range, with mechanical systems based on compressed air and pumped water storage at the high end.

Grid-scale storage of up to 100MW can soak up surplus, off-peak renewable generation and deploy it to fill capacity gaps created when the wind fails to blow. Aside from that, distribution-level storage of up to 10MW can shave peak demand to offset the cost of distribution network reinforcement and provide ancillary services. And it can dig the system out of a hole when a black start is needed or when a large nuclear generator or offshore array falls over.

All useful stuff. How does it fit into today’s market? Right now, it doesn’t. Power storage players want change.

UK Power Networks’ commercial manager Nick Heyward is the hand on the tiller of the distribution company’s Smarter Network Storage project, based on a 6MW lithium-ion battery storage facility currently being commissioned in Leighton Buzzard, Bedfordshire.

“The project is more about market barriers and regulatory barriers than technical ones,” he says. Heyward, like many in the electricity storage game, is critical of what he sees as an absence of regulatory and policy support for storage. He argues that there is much in existing regulation that is “ambiguous” about the rules that apply to stored power and how they are applied.

Dubious definition

Storage is not generation but, by default, it is currently treated as such by the regulator. That brings storage projects owned and operated by distribution network operators (DNOs) up against regulatory buffers. Heyward explains: “Storage looks like generation, and demand. If you treat it as generation you make things difficult because a DNO can’t hold a generation licence. If it’s not generation – and the consensus on that is growing – do we need a new classification or can we do without that?”

About half of the 2GW-by-2020 ambition is expected to be distributed storage with schemes at about 5-10MW. DNOs face investment decisions driven by anticipated radical change in consumption profiles. L ikely culprits of change include smart metering and other connected devices, microgeneration, electrification of heating and possibly electric vehicle use. Being able to abate peak demand with the use of storage embedded in the network could offset conventional network reinforcement costs. The possibility of revenue from storage in the frequency and voltage control services market makes it still more promising.

DNO trading no-go

Putting aside the regulatory definition of storage, there are further obstacles restricting DNOs’ latitude to exploit storage.

There are services, potentially open to a DNO-owned storage plant, outside those created by the proliferation of renewable generation. Some are purely distribution services that displace other expenditure, while others involve trading power. But distribution licences cap sales from non-distribution business activities such as storage at 2.5 per cent of the DNO’s revenue. Investment in non-distribution activities by a DNO is also capped, at 2.5 per cent of its share capital.

A more serious bear trap in the path of DNO storage aspirations is regulation that blocks DNOs from trading energy. That cuts off revenue streams that are likely to be crucial to making a storage business case and attracting investors.

Currently, power in and out of DNO storage projects is treated as losses and spills, so it is unmetered. This would become untenable should storage exit the trial phase to enter widespread commercial operation. In a recent report, consultancy Poyry calculated that every 100MW of storage flow treated as losses would hit other market players’ losses adjustments to their metered volumes to the tune of £3 million a year.

“There is an obligation on us not to distort competition – that’s tricky,” says Heyward. “With storage taking unmetered energy off the system, treated as losses and socialised, it distorts the market. If it is metered, then storage needs to buy and sell energy and that’s currently a no-go.”

Ownership and operation of storage would enable DNOs to add trading revenue to strengthen the business case for storage investment. Poyry looks to Ofgem to unlock this potential: “Action is required from Ofgem to make these options possible (if considered appropriate) through revisions to the regulatory framework,” it says.

However, the favoured option for a DNO looking to play the storage game is, according to Poyry, to find someone else to do the trading.

Energy trading activity to manage inflows and outflows can be handled by a third party supported by contractual arrangements, suggests Poyry. This, it says, avoids the shortcomings of the losses/spill approach and issues relating to potential distortion of generation and supply through DNO trading and is, “the most likely model for grid-scale storage assets in the short/medium term”.

Heyward sees a downside: “It’s a risky business model. How do we ensure the third party is incentivised to deliver peak shaving?” Heyward asks. He adds: “DNOs need confidence that they will provide that service. They would of course have that confidence if they owned the storage.

“Is it possible to get that confidence or will DNOs have to pay too much to make it a goer?”

Pumped storage

Regulatory issues trouble even the one electricity storage technology that is established commercially – pumped storage. Mature pumped storage technology came to the market free from capital costs, courtesy of the British taxpayer, prior to privatisation. New plant will need a different, more testing business plan.

Business director with MWH Global, Craig McMaster, is critical of the lack of encouragement in recent regulatory reform for prospective investors in new pumped storage. “Electricity Market Reform (EMR) does not lend itself well to new pumped storage. I see a need for incentivisation – more done in policy. Investors need to believe there will be return on investment,” he says.

McMaster cites SSE’s £800 million, 600MW project at Coire Glas in Scotland as an example of a project stalled by shortcomings in regulation. SSE has said its investment decision awaits changes in the transmission charging regime for pumped storage and a “satisfactory and supportive long-term public policy and regulatory framework”.

“There should be some sort of allowance – a strike price – to generate certainty for pumped storage,” says McMaster. “We need government policy leadership.”

He looks to Spain, Portugal and France where he says the governments are looking at renewables and storage not separately but in combination.

Pumped storage specialist the Quarry Battery Company (QBC) is looking to exploit a relatively new technology in small pumped storage – plants storing about 500MWh. It is building a 50MW plant in abandoned slate quarries in north Wales.

Managing director David Holmes is a vocal critic of UK infrastructure policy and regulation for creating uncertainty, which deters investors. But Holmes’ criticism of UK policy foibles is tempered slightly by a new hope: the capacity mechanism, introduced under EMR, could have a favourable impact on storage, he says.

“The capacity mechanism was music to my ears,” says Holmes. “It could solve the problem of a secure revenue stream for storage – which has no Renewables Obligation Certificate or FIT etcetera.” But Holmes adds that the open-ended run time obligation in capacity contracts is not viable for storage plant, which have limited output.

Meanwhile, regulatory adjustments in the offing include stiffer penalties in the cash out arrangements under balancing and settlement. The impact they may have on storage is not certain.

The proposed new arrangements would have a single cash out price, making the imbalance penalties significantly more costly. Holmes says this could go either way: “More painful cash-out penalties will drive generators and suppliers to trade to avoid imbalance. That could reduce opportunities for storage. But an increase in the price penalty increases the value of storage.”

Further policy uncertainty for storage may be lurking in the future generation fuel mix.

“If there is more gas it’s hard to say to investors we need more storage,” says Holmes. “And the government is bending over backwards to get gas and coal in.”

Holmes says interconnection with other European markets would ensure that UK shale gas would not repeat the gas price plummet seen in the US. Overall expansion in gas-fired generation “may postpone the market signal for two or three years”, Holmes says.

Regulation, interconnection, market rules and political support for gas are all creating uncertainty for anyone looking to invest in UK electricity storage.

But storage as a tool for DNOs has clear value that is currently not readily accessible. According to public sector body the Low-Carbon Innovation Co-ordination Group (LCICG): “The value of some of the services that storage can provide cannot be easily captured under existing market arrangements.”

Nevertheless LCICG forecasts that the UK will have storage capacity of 27GW by 2050. A separate report by Imperial College predicts 25GW by 2050, while government estimates are 20GW. Clearly for these forecasts to come about, storage technologies must win the economic argument and prove their technical viability. But policymakers must first clear the way.

For the policymakers there are political influences at play, but if they are to back storage they need to get their act together quickly. Storage schemes typically have lead-in times of five-ten years.

Trevor Loveday is a freelance journalist

 

The role of water in priming the sector

Reservoirs could be a feed source for small pumped ­storage schemes

The water sector could have a role to play in bringing on pumped storage. Part of a £240,000, Decc-funded research and development programme at Quarry Battery is an investigation into the possible use of reservoirs as a feed source for small pumped storage plants.

“Pumped storage needs lakes, so why not use ones that are already there and not have to build new ones? Providing there is no burden on water resources, we thought about using reservoirs,” says Quarry Battery managing director David Holmes.

The company’s proposal amounts to using a disused quarry as one end of the pumped storage cycle with a reservoir at the other. Holmes says he is talking to a number of water companies. He acknowledges that there are immediate water treatment concerns about the potential impact of mixing quarry water with reservoir water.

Meanwhile, MWH business director Craig McMaster says a number of water companies have approached the company to assess their redundant assets as possible sites for power production.

“Many have large areas of land, dams that are no longer used as reservoirs and disused pipelines which could lend themselves to pumped storage or conventional hydro,” he says. The companies, McMaster says, are looking both at in-house generation and at selling land or assets to private developers to develop storage schemes.

 

Lowering the cost of electricity storage

A collaborative project between the Energy Technologies Institute and engineering company Isentropic is attempting to prove the feasibility of a new kind of storage technology, which it says could provide a significantly cheaper and more efficient energy storage options for projects of around 1.5MW, or 6MWh.

The technology uses pumped heat, stored in gravel vessels to store energy. To release this potential, gas is expanded in the engine to produce electricity with a round trip efficiency of around 75 per cent.

The demonstrator project has £15.7 million of funding and will be deployed at a primary substation owned by Western Power Distribution in the Midlands. The project is expected to complete in 2018.

Isentropic, which developed the pumped heat electricity storage technology, claims it will provide the cheapest and most convenient way to store and recover electricity to date, and ETI chief executive David Clarke is optimistic about this project – “the economics are quite promising”, he says.

That said, Clarke adds that market conditions are not yet attractive enough for a commercial rollout, however successful the  demonstration proves. “There is no financial mechanism for valuing it,” he says. “Until we can get demand from a market viewpoint, storage will remain a blind spot.”  by Jane Gray