Recent weeks and months have brought a series of key developments for the energy storage sector. Utility Week presents the five most important.

1. The licensing regime

Earlier this month, Ofgem published proposals to clarify the licensing regime for storage by classifying it as a form of generation. Among the aims was to stop storage from being “double counted” as both generation when exporting electricity and as consumption when importing, and therefore contributing to schemes such as the Renewables Obligation and contracts for difference through final consumption levies.

Ofgem opted to amend the generation storage licence to bring storage into the fold, believing this would be simpler, quicker and easier than creating an entirely new licence. But Energy Storage Network chief executive Georgina Penfold believes the regulator may be building up problems for the future.

“I understand why they’ve put it in as generation,” says Penfold “It means less substantial change to the regulation, so they can get it through quicker.

“But storage is not a generator. It is in fact a net consumer and it offers different value to the infrastructure than generation does. We don’t want anything that could in five years’ time reflect back negatively on the industry.”

Tom Edwards from consultancy firm Cornwall Insight welcomes the change, saying it will provide investor-friendly “regulatory certainty”. But, he adds, the practical implications will be somewhat limited.

Storage developers can already “pretend” to be generation to avoid consumption levies, because they are already able to apply for a generation licence. The clarification by Ofgem merely makes it official.

2. DNO-owned storage

At the same time, Ofgem released separate proposals setting out its intention to stop distribution network operators (DNOs) from owning and operating storage, with some very limited exceptions.

The regulator says the change is necessary to prevent DNOs from using their monopolistic power to strangle competition, for example by impeding rivals’ access to their networks or using information that is inaccessible to the wider market. The DNOs argue that the move could prevent them from deploying storage when there is clear benefit to consumers but the market is unable to deliver.

Penfold shares their concerns: “While I absolutely believe we need competition in the marketplace because it drives better pricing, to preclude DNOs from owning something that would enable them to provide a much better service does seem wrong.”

Ofgem plans to allow DNOs to operate storage in very specific circumstances, giving the example of a battery being used to temporarily restore power to consumers during a local power outage. However, the networks would need to persuade Ofgem to grant them exemptions on a case-by-case basis, in each instance proving that it would be in the best interests to consumers and would not harm competition.

Penfold says the success of the rule change will depend on how effectively Ofgem manages this process and what its deems to be grounds for an exemption. “We need to have a clear determination on what a market that is or is not working looks like,” she says.

3. The RO

The month prior, Ofgem also revealed that it would allow three solar farms operated by Anesco to continue to claim Renewable Obligation Certificates (Rocs) for all electricity generated at the sites, even if the power was used to charge co-located storage. It was previously unclear whether such projects would be able to claim Rocs for electricity used to charge storage without applying to be accredited again from scratch, which is no longer possible following the winding down of the scheme over the past few years.

Anesco executive chairman Steve Shine described the removal of this potential barrier as a “game changer” for the storage market. “Ofgem has firmly cemented energy storage as being a vital part of the solution to keeping the country’s lights on,” he says.

It remains to be seen how exactly Anesco managed to work around the rules of the scheme to retrofit storage and retain accreditation, because the company said it was unable to publish its methodology.

Ofgem has promised to clear things up by releasing “bespoke guidance later this year on key storage considerations” under the Renewables Obligation and feed-in tariff mechanisms.

4. The capacity market

In July, the Department for Business, Energy and Industrial Strategy (BEIS) put forward a series of “tweaks” to the capacity market. Most notable was a change to the de-rating factor for batteries (a measure of reliability).

As things stand, all storage has a de-­rating factor of 96 per cent, based on the historical reliability of pumped hydro.

BEIS wants to separate storage into eight different classes depending on discharge duration, each with a corresponding de-­rating factor. The longest-range batteries will retain the current 96 per cent de-rating factor. The rest will see theirs fall.

The changes are being introduced to address fears that some shorter-range batteries may not be able to discharge power for the full duration of a stress event, and are therefore not as reliable as their current rating suggests.

However, BEIS has yet to reveal the de-rating factors for the different classes of storage. As capacity contracts are paid according to de-rated capacity, Edwards says this is major concern for developers looking to bid into the next main auction in early 2018 who still don’t know what their bids will be worth. “It’s not the ideal way to have done this change, and that’s putting it mildly,” he says.

5. Ancillary services

In June, National Grid released its System Needs and Product Strategy consultation, which detailed plans to overhaul the procurement of ancillary services to facilitate the transformation of the energy sector.

As the document explains, the requirement for ancillary services is expected to swell over the next decade and a half because of the increased penetration of intermittent renewables and the closure of conventional generation.

Edwards says the main areas of interest for the storage market will be the system operator’s plans to revamp frequency response and its efforts to find some way to provide value for system inertia, although not through a specific market.

Frequency response contracts were the driving force behind the breakthrough of 500MW of battery storage in the most recent capacity market auction. Ancillary services remain “the only route to market” for grid-scale lithium-ion batteries, according to Edwards, and the consultation raises plenty of questions for developers.

“Is there going to be FFR-like [Firm Frequency Response] products?” he asks. “Will there be an inertia project? Will there be another EFR-like [Enhanced Frequency Response]? How will these products interact? Will they be easily comparable? Can I transfer them. Can I stack them?

“All these sorts of questions are unknowns, because National Grid has not yet told us what these products will look like in the future.”

Penfold is optimistic: “I think we’re going to see some good things coming out of that. Certainly, National Grid has been engaging really well with our members.”