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Amendments to the laws have passed both Commonwealth Houses of Parliament.
In 2016 we teamed up with SgurrEnergy (now the Wood Group) to discuss the potential revenue streams for storage projects, challenges for collocating storage, and some of the regulatory issues that applied at the time1. Since then, things have in some ways moved on in leaps and bounds. In other ways, little progress has been made.
The 2016 Enhanced Frequency Response (EFR) tender round in many ways represented a high water mark for battery storage projects in the UK. Changes in the ancillary services market and capacity market have caused the sector to review business models, pushing new assets to favour more nimble structures. There is no doubt that there is a role for electricity storage in delivering the flexibility required for future energy systems, particularly given the need for the integration of higher volumes of electric vehicles and intermittent renewables into the energy mix. The result is a diversification of the types of storage projects and business models we are seeing coming to the British market. In the last year we have acted on stand-alone and co-located lithium-ion battery storage assets, as well as the refurbishment of a pumped storage power plant. In that context, regulation is struggling to keep up and a number of consultations are still “out”, with decisions pending.
With the Future Energy Scenarios (FES) report, launched in July 2018, projecting storage to grow from 2.9GW in 2017 to between 5.9GW and 9GW by 2030, it is clear that storage will continue to play an ever more important role in the energy market in Great Britain. In this briefing, we consider the current state of play of regulatory reform.
In 2016 it was uncertain how the addition of battery storage facilities to existing renewable energy generation facilities would impact those projects’ energy accreditations, under Feed-in Tariffs (FiT), the Renewables Obligation and Contracts for Difference (CfD). The loss of accreditation or eligibility under such schemes would be catastrophic for a project.
The regulator, Ofgem, has now confirmed that the addition of storage to renewable energy projects receiving support under the FiT or Renewables Obligation regimes can be accommodated under these schemes subject to certain criteria (with an emphasis on metering arrangements), paving the way for increased co-location of renewable and storage assets. With final guidance published in June 2018, this should make it easier to secure funder consent in respect of any modifications to existing renewable energy projects that are seeking to retrofit battery storage.
Under the CfD regime, to ensure that CfD generators would not be paid for stored electricity which is imported from the grid or produced from non-CfD generating units, the CfD standard conditions were amended in advance of the second allocation round. There are now two ways for a CfD generator to incorporate storage alongside the CfD eligible generating facility, without risk of the CfD being terminated; first, a balancing mechanism (BM) unit can be obtained for the storage asset that is separate to the one associated with the generating facility, or secondly, if the same BM unit is to be used for both the storage asset and the generating facility, then the CfD counterparty must be satisfied that the metering arrangement is such that the storage asset can only store electricity generated by the generating facility and not import electricity from any other source.
|Case study: Co-location
Equinor has launched Batwind, a battery storage solution for the Hywind Renewables Obligation accredited offshore wind farm. Batwind will be developed in co-operation with Scottish universities and suppliers, under a new Memorandum of Understanding between Equinor, the Scottish government, Offshore Renewable Energy, Catapult and Scottish Enterprise. The storage is intended to mitigate intermittency and optimise output. This is reported to improve efficiency and lower costs for offshore wind. Equinor will install a 1MW lithium battery based storage pilot system in late 2018. This is equivalent to the battery capacity of more than two million iPhones.
There has not been a separate electricity storage licence with energy storage activities instead treated as generation facilities and licensed where they were of sufficient size to require a licence.
Ofgem and the government have already agreed that it is important to ensure regulatory consistency between both storage and electricity generation. They believe that the existing electricity generation licence is the best vehicle for clarification of the regulatory framework for storage whereby it would be included in the Electricity Act 1989 as a subset of generation. This should also be a quick way of implementing a specific licensing framework for storage and will mean that existing licensed storage assets will not need to reapply for a new licence.
The outcomes of an Ofgem consultation, which closed on November 27, 2017, are still awaited with such consultation considering
Following the implementation of these changes, storage providers should have better clarity over which industry codes they need to sign up to and as such, what obligations apply to them.
The proposed definitions of storage for the licence have already been widely discussed in other forums. It is proposed that “Electricity Storage” in the electricity system is “the conversion of electrical energy into a form of energy which can be stored, the storing of that energy, and the subsequent reconversion of that energy back into electrical energy” and “Electricity Storage Facility” in the electricity system means a facility where Electricity Storage occurs.
Certain types of energy storage would therefore not fall within the proposed definition of electricity storage (e.g. thermal energy storage when the stored energy is not re-converted to electricity before use but is used directly as heat). Work is progressing separately to define electricity storage in the Grid Code. In that context, industry has suggested adding the phrase “in a controllable manner” at the end of the definition of “Electricity Storage” set out above. Ofgem is considering whether to align these definitions.
Much of the early work around energy storage in the UK involved Distribution Network Operators (DNOs). For example, the Low Carbon Networks Fund allowed up to £500 million to support projects sponsored by the DNOs to try out new technology, operating and commercial arrangements. The Leighton Buzzard project successfully trialled a 6MW/10MWh grid scale battery, with sufficient storage capability to power 6,000 homes for 1.5 hours at peak times.
However, DNOs’ ownership of storage assets has long been seen as conflicting with principles such as unbundling. Currently DNOs cannot directly own or operate large-scale storage over 100MW. Below 100MW, and linked to the generation licence exemption, there is a grey area where DNOs can own smaller scale storage.
In September 2017, Ofgem released a new consultation document proposing changes to the electricity storage licensing regime. If approved, the new regulations will seek to prevent DNOs from using consumer-funded battery storage facilities to sell services to the National Grid. Ofgem indicated that if the consultations progressed as they hope, distribution licence modifications would come into effect in Summer 2018. As at the time of writing, there have been no further updates with respect to timings.
A new condition 43 B proposed for the Electricity Distribution Licence is intended to ensure DNOs are legally separate from the operation of storage facilities, regardless of whether the asset is licence exempt. DNOs would require consent from Ofgem in order to carry out any generation activities, which includes storage activities, save for small scale applications and emergencies. Such restriction would be replicated in relation to Independent DNOs.
This may give further impetus to “storage service providers”, a model already considered as a way around earlier but less restrictive requirements for DNOs. DNOs will be able to contract with third party storage service providers, even if they are (legally separate) affiliates of the DNOs. Questions remain over the future of DNOs ownership of existing storage assets, though the consultation proposes that DNOs could continue to own storage and generation assets for now. Ofgem have made clear however that the arrangements for existing storage assets owned by DNOs will not give precedent for the treatment of future storage projects by DNOs.
We expect that DNOs will continue to be heavily involved in the development of new solutions as a means of avoiding costly network upgrades. For example, Northern Power Grid has participated in storage projects in Darlington and Barnsley, deploying batteries to social housing to enable more roof-top solar to connect.
The proposed no “self-consumption” licence condition will mean that where the relevant requirement can be complied with, licensed storage facilities should no longer have to pay the cost of final consumption levies. Storage uses electricity in order to be able to store it. When energy is converted and exported again to the end consumer, this can result in a ‘double charge’ of the supply of electricity to the end consumer and in a payment of levies by both the storage provider and the consumer of the same electricity. Costs of final consumption levies are passed on to consumers in order to fund the Renewables Obligation, FiT, CfD and the Capacity Market.
The proposed “no self-consumption” licence condition requires that the primary function of the storage facility is to export electricity back to the distribution system or to the national electricity transmission system. It would prevent the facility from being treated as the ‘end consumer’, thus avoiding paying the final consumption levy costs. If the storage facility’s primary function is not to export to the distribution or transmission system, then such facility will not be classified as storage for regulatory purposes and would be subject to final consumption levies.
Generators and storage operators are both liable to certain use of system charges; Transmission Network Use of System (TNUoS) charges and Balancing Services Use of System (BSUoS) charges on the electricity they generate and use. Storage operators are however more exposed than generators to these charges because of the amount of electricity imported (so subject to demand charges) and exported (so subject to generation charges). This contrasts with generators, for whom imports are a small proportion of exports.
In recognition of this potential competitive distortion between generators and storage providers and in order to address such distortion, two proposed modifications are now going through the CUSC modification process, with the authority determination date currently anticipated to be in January or February 2019. The modification in respect of the TNUoS tariff, if approved, would see a lower level of TNUoS tariff introduced in respect of the import of electricity by generators and storage providers. The modification in respect of the BSUoS tariff would see an amendment such that the energy imported from storage facilities does not attract BSUoS charges.
The revenue stream for providing storage services is typically a “stacked” series of revenues from different sources. This contrasts strongly with some other jurisdictions where a single entity will agree to pay a single capacity/availability charge, or to markets where large peaks and troughs in power prices make a price arbitrage model more attractive. In Great Britain, these stacked revenues typically include frequency response revenues, capacity market revenues as well as other revenues such as from participation in the BM. Offering layers of services may reduce revenue available from another service due to a mismatch in the technical or contractual requirements between services. A particular problem has been having the systems “chase” such revenues and understanding how to prioritise particular revenues in certain circumstances.
In July 2016 National Grid awarded 200MW of EFR contracts. Tenderers had to deliver an EFR service capable of operating at maximum charge or discharge for a continuous period of 30 minutes. This provided a significant boost to battery storage. However, there was always uncertainty about the future of EFR revenues and the EFR contracts between service providers and National Grid were only granted for a four-year term.
Last year National Grid consulted on the ‘System Needs and Product Strategy’ (SNAPS) and outlined the system operator’s system balancing needs (Response, Reserve, Reactive Power, Black Start and Inertia). Since then, National Grid has gone on to publish a number of “Product Roadmaps”. One such Product Roadmap was published in December 2017 whereby National Grid has detailed the removal of a number of its frequency control products: Firm Frequency Response (FFR) Bridging, Frequency Control by Demand Management and Enhanced Frequency Response; from active procurement and endeavour to meet frequency response requirements in a more transparent and competitive way. The remaining frequency response routes to market will be procured through a monthly FFR tender and a mandatory within-day market. National Grid intends that contract duration will be a maximum of thirty months.
Storage operators will not have existing contracts cancelled but will be keen to understand better likely sources of future revenue streams. Lack of availability of long-term contracts has been cited as one of the reasons that project finance is particularly difficult for storage assets, so this may have an impact on the future long-term “bankability” of projects. That said, storage operators are used to operating with short-term revenues and have relied on equity finance rather than project-level debt to date.
In May 2018 National Grid published Product Roadmaps in relation to both reactive power and system restoration. Of particular note are the changes to black start services with National Grid expressing a wish to remove barriers to entry to allow improved market access to a broader range of potential participants, including storage. The changes are being driven, in part, by a changing generation mix, with increased renewables and smaller thermal generation plant connected to the distribution system. Traditional black start providers assets (for example coal fired power plants) are on-line less frequently than in the past meaning they may not be available for black start services at a given time. National Grid will look to storage/batteries from Q3 2019 to explore their potential, coupled with the concept of combined service provider solutions (or perhaps on a standalone basis), to offer black start services.
Capacity market contracts were a good source of revenue for battery storage projects. New build contracts benefited from a 15 year tenor so provided a solid foundation for storage business cases. However, in its response to the consultation on improving the framework of the capacity market, published on December 4, 2017, the government confirmed its decision to amend the “de-rating” factors for storage in capacity market auctions from the previously set level of 96 per cent for those storage units that have a duration of less than four hours which has significantly reduced the revenues available for some technologies. In essence this means that the incentives that would have been available to shorter-duration battery projects have been revised downwards in order to account for the relatively short time after which some batteries would require to be recharged after a stress event. In the T4 auction for delivery in 2021/22 for example, a de-rating factor of 17.89 per cent was applied to the shortest 30 minute duration sub-class.
A record low clearing price, coupled with the changes in de-rating factors meant that just 153MW of battery storage secured contracts in capacity market auctions held earlier this year, with developers unwilling or unable to accept contracts at a historically low price point. This compares to the previous year where over 500MW of battery storage projects secured capacity market contracts. While many in the industry are critical of the timings of announcing the derating of batteries, others see the de-rating of shorter duration storage as appropriate and necessary to incentivise developers to think about building longer duration storage assets.
We think a number of trends will continue to develop in the energy storage space:
Those investing in or looking to finance battery storage will increasingly need to accept a degree of risk for merchant revenues. Investors therefore will be looking for partners with experience of managing risks in electricity markets and a track record in overcoming regulatory hurdles. Sophisticated models that can cope with managing revenue stacking will also be required. Investors will continue to look to good asset warranties, particularly ones that permit storage facilities to be used for a variety of future purposes, in order to help mitigate any future risks of changes of income flows or operational strategy, for example. Confidence in an experienced management team will be essential. Adopting a portfolio approach to allow spreading of risk with a diversity of assets of different types and scale will enable project risk to be spread across a cross-collateralised portfolio. However, despite these challenges, investors can take comfort that, unlike a pure solar PV play, the storage sector is not built on the back of government subsidies. That being said, it operates in a rapidly changing market which key players such as Ofgem and National Grid are trying to adapt for the future. This creates opportunities as well as risks.
EVs integrated into the distribution network are likely to be a driver for grid congestion but, if combined with smart technology, may also offer new business models for commercial and domestic scale storage, particularly when combined with demand-side management. The economic ramifications and physical and regulatory challenges are difficult to predict as yet but already businesses are considering energy as a service, with Nissan moving towards a combined vehicle, battery and solar panel leasing scheme. With Ofgem’s announcement of a review of electricity supply market arrangements, new business opportunities may be on the horizon2. In addition, further opportunities lie in overall energy management systems, and the repurposing of “old” EV batteries for home or grid-scale energy storage. Nissan believes that today’s Nissan EVs in the UK could represent 220MW of storage already.
|Case study: Vehicle to grid systems
Nissan, whose electric cars are amongst the best-selling in the world, has announced a partnership with Nuvve, National Grid, UK Power Networks, Northern Powergrid, Newcastle University and Imperial College London to develop electric vehicle to grid (V2G) systems. The partnership, which has received a £9.8 million government grant, is to investigate how EVs can maximise the use of energy generated from renewable sources. Chargers will be controlled by an aggregator and data will be collected to understand how the system could be used both for charging vehicles and providing back-up to the national grid.
We will continue to see innovation in this space, which will mean that regulations will need to be flexible to keep pace with developments. For example, Open Utility want to be the “ebay of flexibility services”; they are a software company developing a single platform for electricity storage procurement. Automated grid and power trading models that rely on blockchain or distributed ledger technology based platforms are likely to become increasingly prevalent. For more information, please see our publication: Unlocking the blockchain: Digitizing the energy value chain3.
While progress towards regulatory clarity is welcome, for some in this nascent industry the pace of regulation is not quick enough. For others, the abruptness of change (for example de-rating of storage in the capacity market auction) has forced a review of business models to find alternate revenue streams (or technology) to make the business case stack-up. Financiers are closely watching the storage space with some considering short-term debt deals that can match the shorter term nature of contracts.
The decentralisation of electricity generation and increasing penetrations of renewable generation, together with need to make inroads towards the decarbonisation of heat and transport, are among the factors driving the longer term need for energy storage. Despite the considerable number of challenges, the energy storage market in Great Britain continues to expand, and continues to attract strong interest from both traditional energy players and newer disrupters keen to exploit the long term significant growth trends.
Scaling up energy storage in the UK, September 2016: http://www.nortonrosefulbright.com/knowledge/publications/142557/scaling-up-energy-storage-in-the-uk.
Amendments to the laws have passed both Commonwealth Houses of Parliament.
Canadian National Railway Company v BNSF Railway Company adds to recent case law that has seen the Federal Court refuse to issue routine protective orders.