The increasing amount of intermittent generation on the system, coupled with improving technology and lower costs, should create the right conditions for electricity storage to play a key role in the UK energy market. However, barriers to achieving successful commercial deployment remain.
Removing these barriers will involve the whole industry - in securing an appropriate regulatory framework for storage, identifying new approaches to network management and the procurement of network management services, the structuring of innovative route-to-market products, the continued development of cost-effective technology solutions, and the development of funding models.
This article outlines some of the key barriers and how they may be addressed.
What is electricity storage?
UK energy regulation does not recognise electricity storage as a distinct activity. Electricity storage is not therefore regulated in the same way as generation, networks or supply. As will become apparent from the rest of this article, there are a number of points that flow from this first issue.
This absence of regulation can (perhaps counterintuitively) present problems.
The absence of a distinct regulated activity means that electricity storage falls to be treated under the industry arrangements as a combination of generation and supply/consumption. The treatment of storage in the same way as generation, or in the same way as supply/consumption, may be appropriate in some cases. The current treatment has, though, arisen by chance rather than design. The regulation of storage should be considered afresh to determine how storage should, on its own merits, be treated - this is relevant to the renewable electricity incentive mechanisms, the industry codes, and the industry charging methodologies.
The absence of a comprehensive regulatory regime is also problematic in that it creates uncertainty for participants, as there is an ongoing risk that any regulatory framework that is ultimately imposed does not reflect their business model.
A re-casting of the licensing framework and renewable electricity incentives are matters for central government, and would need to be considered in the context of the EU Electricity Directives. However, there does appear to be the political will to change legislation where necessary to facilitate the development of storage - those involved in storage were among the few to take positives from Amber Rudd's November statement on UK energy policy. The National Infrastructure Commission has also issued a call for evidence that covers electricity storage.
There is also a fair amount that can be done by the code bodies - with the support of Ofgem - to amend the industry codes and charging methodologies.
What is electricity storage (again)?
This time from a tax perspective:
The remainder of this article is concerned with matters of energy regulation. However, there is another important area in which the classification of storage requires clarification/reform - the perspective of UK tax.
For example, when the UK Government announced the proposed closure of Enterprise Investment Schemes (EIS), Seed Enterprise Schemes (SEIS) and Venture Capital Trusts (VCTs) to electricity generation projects, did they mean this to include storage? EIS, SEIS and VCTs offer tax advantages to investors. They were originally closed to renewable electricity generation on the basis that renewable electricity generation already benefited from incentives. The proposed Finance Act 2016 is currently worded in a way that will prevent all electricity generation and electricity storage projects from benefiting under these schemes. The Finance Bill 2016 is currently the subject of consultation.
The role of Electricity Distribution Network Operators (DNOs)
The important role that electricity storage can potentially perform in deferring or avoiding the need for electricity distribution network reinforcement has been acknowledged via the Low Carbon Network Fund (LCNF). These LCNF projects were run through the electricity distribution revenue restriction conditions. Indeed, one of the most high-profile recent projects has been UKPN's project at Leighton Buzzard, which was developed via the LCNF.
However, the current regulatory framework restricts the ability of DNOs to participate in electricity storage due to standard electricity distribution licence conditions. These licence conditions were established as part of the business separation requirements for vertically integrated electricity utilities.
One option is to exempt storage from these restrictions so that DNOs can become active large-scale developers of electricity storage. Such an approach is perhaps unlikely though - the same concerns regarding access to networks that arise in the case of generation are likely to be relevant to storage.
Another option - and perhaps the more likely approach - would be to change the regulatory framework so that DNOs are obliged and/or incentivised to become active buyers of storage services. Independent developers would then participate in a competitive market to provide DNOs with the system support services that they need. Just as National Grid buys ancillary services and balancing services via competitive markets, DNOs would do the same - identifying areas where storage could deliver benefits to their networks and seeking provision of storage in those areas under long-term contracts.
Provision of balancing services and the capacity market
Transmission System Operator support services are a key income stream for any large-scale electricity storage project. In Great Britain, storage projects will be able to secure income via National Grid's balancing services and (potentially) via the Capacity Market auctions. In Northern Ireland, the position will be dependent on the outcome of the I-SEM design.
There are no apparent regulatory barriers. Storage developers do not currently have - and probably cannot in the future expect - any additional incentive or support, but there is at least a level playing field. In fact, the relative flexibility (in regulatory terms) that National Grid has in determining the type of services that it needs in order to balance the network, means that markets for new types of balancing services may develop relatively quickly.
Indeed it is already happening, as is evident from National Grid's invitation for expressions of interest for Enhanced Frequency Response. This is expressly aimed at procuring services that battery storage projects are likely to be best able to deliver. A key sticking point will, however, be the length of the contract to which National Grid is able to commit. It appears likely that National Grid will offer four years - no doubt developers would have liked longer, but this is an improvement on the two years that initially seemed likely.
DECC is currently considering its decision on the recent Capacity Market reform consultation.
Co-location with renewable generation
The co-location of electricity storage projects with solar PV projects is seen as one of the most attractive options for commercial development of electricity storage projects. By co-locating the projects 'behind the meter' there should be opportunity to access higher power prices by smoothing the export profile and shifting the peak generation to a time of peak demand. Co-location may also help alleviate the constraint issues to which some intermittent generators find themselves subject.
However, those that operate (and, perhaps even more acutely, those that have funded) solar PV projects will first and foremost want to preserve their current income streams. The increased power revenue will count for nothing if the electricity storage project jeopardises the renewables incentives to which the solar PV project would otherwise be entitled.
This risk arises in relation to Renewables Obligation Certificate (ROC) projects particularly. Electricity generated by the solar PV project will only be eligible for ROCs if the electricity is supplied by a licensed supplier or used in a permitted way. Projects will need to be structured in a way that ensures that this is the case.
Funding renewable incentives (double counting)
The other aspect of interaction with the renewable energy schemes is the treatment of electricity storage under the mechanisms by which renewable incentive schemes are funded.
For the most part, the costs of UK renewable energy schemes are met by electricity suppliers, and are allocated between suppliers by reference to their supply market share. This brings us back to the treatment of storage as supply/consumption. If the electricity used to charge the storage device is supply, then the electricity supplier should count this supply as part of its market share calculation. Consequently, the power is counted twice - on charging the storage device and on its subsequent supply to the end-user following discharge. If this is the case, then it seems an unfair disadvantage for storage.
Treatment under other industry charges
Triad avoidance benefit offers a key income stream for electricity storage projects. Similarly, there will be opportunities for income via load/generation shifting to access more favourable distribution use of system time bands.
However, the charging structure of some industry charges does not currently appear to properly reflect the impact of storage on the network. For example, the common distribution charging methodology does not expressly deal with storage, let alone co-located storage and generation. If the DNO applies an intermittent generation tariff this might place a cost on the project that does not accurately reflect its role in supporting the network by levelling the peaks in supply and generation.
Changes to charging methodologies can be proposed by any participant, and will be progressed through the industry code change processes.
Accessing the multitude of income streams
As will be apparent from the analysis above, electricity storage projects will be dependent on a number of different income streams. In contrast to renewable projects, there is no 20-year incentive scheme support. Developers will need to become adept at accessing these different income streams. This complexity is unavoidable to a degree, but DECC, Ofgem and the network operators must seek to ensure that there is no unnecessary conflict between the schemes. Where participation in one scheme is intended to prevent participation in another, this should be made clear.
Many storage operators will enter into a route-to-market power purchase agreement (PPA) with an electricity supplier or aggregator, via which the storage project is able to access day-ahead and spot market prices and via which Triad and other embedded benefits can also be realised. Where the project is co-located with generation or demand, there will also be a contract with the host. The final piece of the jigsaw is likely to be a balancing services contract with National Grid.
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