energysource issue 18 03 Apr 2017 Battery Storage: A charged future

After years of being "the next big thing", battery storage has finally built up sufficient momentum through reduction in cost and improvements in technology to be commercially viable in grid-balancing, frequency response and demand-side management applications. The UK Government's call for evidence on smart grids of November 2016 and changes to the Contracts for Difference standard terms in February 2017 are indicative of a rapidly improving regulatory landscape with many opportunities for potential investors. This article covers the core information energy professionals need to understand utility-scale and demand-side battery storage, with a specific focus on the issues facing the UK market and recent and upcoming regulatory changes.

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What is grid-scale battery storage and why is it important?

In simple terms, battery storage is the storage of electrical energy as chemical energy for future re-conversion to electrical energy on demand. Historically, energy storage of any kind has been difficult, costly and subject to a number of limitations which have largely meant that, for most electrical grids, the rate at which electricity is consumed must more or less be matched by the rate at which it is generated at all times. This characteristic of electricity networks has defined the structure of the electricity industry and networks around the world. The rapid rise of large-scale battery storage in recent years has the potential to dramatically alter this picture.

As battery technologies have improved, materials have reduced in cost and the benefits of scaled roll-out have begun to apply, grid-scale and demand-side battery storage has been gaining ground as a solution to a number of balancing issues increasingly facing modern electrical grids. As a result we are now beginning to see the first signs of commercial roll-out both in the UK and internationally. Battery storage is being touted as an economically feasible and more rapid provider of reactive power for grid frequency stabilisation, an effective localised approach to smoothing out daily cyclical variations in demand and, in the future, the key to unlocking the full potential of large-scale intermittent generation.

For the purposes of this article, we focus primarily on large-scale, grid-connected battery storage, often referred to as "utility-scale" or "grid-scale" energy storage, though we also consider demand-side battery storage (used in conjunction with large consumers of electricity) as another important emerging trend. It is arguable that, in contrast to these large-scale energy storage applications which are just reaching maturity, the small or micro-scale battery energy storage revolution has already happened over the last 15 years – in particular, the development of lithium-ion batteries has paved the way for all the portable electronic devices we take for granted, as well as electric cars. In contrast, large-scale energy storage has some catching up to do, but, as discussed below, we are now on the cusp of an industry transformation.

Historical context

The enormous potential value of grid-scale energy storage has long been recognised. As early as the 1930s the development of reversible hydroelectric turbines allowed for a form of pumped energy storage: filling reservoirs during times of low demand and generating electricity at times of peak demand. There is now approximately 120 GW of worldwide pumped storage capacity, but further roll-out is hampered by a need for very specific geography, high capex costs and significant efficiency losses inherent in the energy transitions involved (averaging no more than 70 to 80 per cent round-trip efficiency). Pumped storage is also generally only suited to predictable cyclical balancing roles, with only the newest variable speed turbines being capable of the rapid response times and controlled output needed for intermittent generation balancing and frequency response applications.

Other methods of grid-scale energy storage have been investigated (such as storage of energy through compressing air, creating hydrogen from hydrogen electrolysis, storing kinetic energy in flywheels and storing heat in various forms). However, cost, engineering challenges and round-trip efficiency remain major barriers to large-scale adoption.

Battery storage, benefiting from iterative technology development and decreasing cost in the consumer and transport spheres, as well as high round-trip efficiencies (newer batteries achieving in excess of 90 per cent), has rapidly emerged as a major grid-scale energy storage contender.

By the 1990s, lead-acid battery storage was already seeing widespread exploratory use in grid stabilisation and frequency response applications as a source of rapid reactive power. Early projects focused on isolated or remote grids where reliability and frequency or voltage stabilisation might otherwise have been an issue, including a 20 MW, 5 MWh system in Puerto Rico and a 27 MW, 6.75 MWh bank in Fairbanks, Alaska. Bulk, cycle life and lead acid's toxic materials continued to be the primary drawbacks, though these are beginning to be addressed in modern iterations of the chemistry (see "Battery technology primer" overleaf).

The development in the 1990s of more energy-dense lithium-ion batteries, and their decrease in cost over subsequent decades, led to their explosive growth in the consumer electronics and electric vehicles markets. With lithium-ion battery costs plummeting between 11 and 24 per cent (depending on application) in 2016 alone, and production increasingly scaling up, grid-scale battery storage using lithium-ion batteries has now become viable. In the United States alone, as much as 1,800 MW of new battery storage, largely lithium-ion, is expected to come on line by 2021, with project sizes ranging from 2 to 30 MWs.

There is now near consensus from industry that battery storage will play an important role in the future development of the UK electricity grid. Tim Barrs, who heads energy storage sales for Centrica, said recently that past concerns about the bankability of battery storage projects are giving way to a flood of investor interest as understanding of (and confidence in) the technologies and related revenue streams grows.1  In his view, a rush of investment decisions will likely be announced by summer 2017, with the market developing very rapidly thereafter.

How do you solve a problem like grid balancing?

The need for electricity supply and demand to be actively balanced across a grid creates some complex challenges. Battery storage has the potential to assist system operators in addressing system imbalance in a number of different scenarios: imbalance caused by changes in demand, imbalance caused by changes in supply, and managing stable electrical frequency levels across the grid.

Frequency response

Smooth grid operation relies upon the provision of rapid reactive power services (either by generators or dedicated facilities) to enable fine-scale frequency stabilisation of the grid on a second-by-second basis to smooth out deviations from the network's baseline 50 or 60 Hz frequency. Historically this need has been met by generators modifying their output on demand and dedicated reactive power services (largely provided by gas plants, flywheels and variable-speed hydropower). These traditional methods have a reaction time of under ten seconds. By contrast, battery storage can provide sub-second response times and has therefore, unsurprisingly, already begun to dominate this application in many jurisdictions.

In merchant electricity markets a fee is typically paid by the balancing authority for grid frequency stabilisation services, and it is this role and revenue stream which has led to the first non-demonstration, economically viable, grid-scale battery storage projects in various countries including the US, Japan, Korea and Germany. In the UK, as part of its Enhanced Frequency Response scheme, National Grid ran a technology-neutral auction for 200 MW of frequency response capacity in July 2016 in which battery storage was the biggest winner (see below).

Responding to fluctuations in demand 

Electricity demand in a typical national grid varies dramatically over time, and balancing demand and supply in real time has proven an increasingly complex challenge as intermittent resources enlarge their role as a source of electricity. Some elements of electricity demand variation follow clear patterns, such as seasonal demand changes and daily peaks and troughs in usage. The difference between the lowest levels of daily electricity use (overnight) and peak electricity demand can equate to almost a doubling of demand, and a similar difference applies between the average summer and winter usage. Other variations are more difficult to predict – an advert break at half-time in a popular sporting event, for example, can see a significant spike in demand as millions of people switch on their kettles.

While base-load sources of electricity such as nuclear and coal power provide a reliable and consistent supply over long periods of time, they cannot quickly or cost-effectively be reactively brought on and off line, and intermittent sources such as wind and solar are, by their nature, completely incapable of reacting to demand. The need for cyclical and reactive "peaking" generation, therefore, has historically been met by generation sources able to stop and start to some degree on demand, such as gas turbines and hydropower plants. Battery storage has begun making inroads into this market as a flexible, modular and perhaps even cheaper alternative to traditional models, especially in urban areas.

As costs have fallen, battery storage has begun to be used in grids to provide a replacement for peaking generation required to meet peak daily demand, especially in more fragmented grids such as in the USA, where localised balancing is critical. Projects being developed by major utilities generally target the four hours of peak demand (typically between 4.00 p.m. and 8.00 p.m.) – aimed at bridging the peak electricity consumption hours without the need to build new gas peaking generation capacity in urban and sub-urban locations, where obtaining the necessary land and authorisations can be problematic.

Responding to fluctuations in supply

As well as swings in demand, the grid must be able to adapt to unexpected changes in supply. Generating plants suffer outages or reductions in output, and electricity output from intermittent renewable energy sources by their nature cannot be firmly relied upon. Reacting to unpredicted changes in supply in a matter of minutes requires electricity sources with very short start-up times, a role historically filled by gas turbine plants and more recently diesel generators. As modern grids increasingly rely on intermittent sources, building new large-scale gas turbine plants has long been a priority in many countries. However, in merchant grids where generators rely on the sale of electricity for revenue, making an economic case for investment in new large gas plants, which operate cost-effectively only at times when insufficient intermittent generation is available, has proved difficult. The UK Government has been attempting to address this issue through its Capacity Market (CM) incentive mechanism as part of its Electricity Market Reform measures, but has had limited success thus far in encouraging new large-scale gas-fired power plant construction due to significant capital costs, uncertain long-term political outlook for fossil-fuel-based generation and the domination of the CM mechanism by cheap (and dirty) diesel generators. Against this background, and the lack of sufficient investor interest in large-scale new gas projects, the potential opportunity for the use of grid-scale battery storage in this role is obvious.

In addition, as western countries invest in ever greater proportions of intermittent renewable generation, the need for standby peaking capacity has grown as a corollary to meet demand when intermittent sources are not generating, or to shift electricity which is generated at times of low demand to peak periods when demand is greater (generation from wind, for example, tends to be greater at night when electricity demand is at its lowest). Mitigation of intermittency costs becomes ever more valuable as the proportion of generation provided by intermittent sources increases. While frequency response has launched commercial grid-scale battery storage projects in earnest in the UK, it is likely that battery storage's potential role as a peaking provider of electricity deployed in tandem with intermittent sources will see it truly take off, including through future iterations of the CM mechanism, to complement the UK's increasing use of wind and solar power (discussed below).

As a corollary to bringing new sources of electricity on line to address drops in supply, system operators have increasingly been looking at ways in which demand in the system can instead be reduced when needed, a process described as demand-side management or load-shifting. Deliberately varying demand on the grid can allow big consumers of electricity to benefit from greater free generating capacity and in some cases cheaper electricity prices at off-peak times. Demand-side management can be greatly enhanced by the ability to take and store electricity, through charging batteries at off-peak times of day, allowing for the stored energy to be used during peak hours.

In future, smart grids, with time-dependent consumer electricity costs, will likely be increasingly relevant, and particularly important for those energy-intensive industries which cannot operate only during off-peak hours. Similarly, the last decade's explosive growth in rooftop solar panels and other distributed generation has seen mains-connected battery storage (most notably Tesla's "Powerwall") marketed to consumers to complement their home solar set-ups in a "behind the meter" configuration which allows for more careful control of the times at which the consumer draws electricity from the grid.

Battery technology primer 

There are a number of competing battery technologies which have seen significant adoption for grid-scale storage (with many more at an earlier development stage), each having characteristics that make them suited for different applications in the grid-scale storage market.

  1. Lead acid – a mature technology, lead-acid batteries account for as much as 50 per cent of all battery use worldwide, primarily in the form of car batteries.  While lead-acid batteries benefit from their low cost and reasonable safety characteristics, they contain toxic materials and have low energy densities.  Lead-acid batteries were utilised in many of the early demonstration projects for grid-scale battery storage and account for around 25 GW of installed storage capacity in the US alone.
    UltraBattery, a new iteration of the lead-acid battery which addresses some of the chemistry's drawbacks, has seen considerable early uptake in both transportation and grid-storage applications.  A number of US projects using UltraBatteries co-located with wind plants have been commissioned or are under development, including the completed PNM Prosperity test project in New Mexico (which co-locates 1 MW of batteries with a solar PV facility).
    Though lead-acid batteries have been somewhat overshadowed by the more energy-dense lithium-ion batteries in the transportation and consumer spheres, they continue to shin in grid applications because of their low cost, safety profile and established (and highly effective) recycling and reuse infrastructure, all areas in which lithium-ion batteries are (currently at least) less able to compete.
  2. Lithium-ion – the term lithium-ion refers to any one of a range of different lithium-anode-based rechargeable batteries, the first of which became widely commercially available in the early 1990s.  Lithium-ion batteries have become increasingly commonplace due to their high energy densities and falling costs, though they generally remain more expensive than the older lead-acid and nickel-cadmium battery technologies. Exact characteristics vary depending on the particular lithium-ion anode and cathode materials used, with some carrying explosion or overheating risks as a trade-off to increased performance, operating life or energy density. 
    Major electric vehicle industry figures including Tesla and Nissan have identified that the same lithium-ion battery technologies they use in their electric vehicles can be profitably utilised in consumer/commercial premises for demand-side and distributed-generation storage applications, as well as in grid-scale applications (when produced in a modular, scalable form). Nissan has taken this concept a step further, firstly by developing the xStorage device which uses recycled electric vehicle batteries in parallel to provide a storage solution, and secondly by developing plans to connect 100 vehicle-to-grid charging units across the UK to allow parked electric vehicles to be used overnight in a limited backup balancing capacity on the grid. Several other car manufacturers are also investigating these opportunities or actively developing projects.
  3. Nickel-metal hydride – developed in a similar time frame to lithium-ion batteries, nickel-metal hydride batteries built on the success of early nickel-cadmium rechargeable batteries. While lithium-ion batteries have much greater energy density and lower cost, the higher safety profile and excellent cycle life of nickel-metal hydride batteries has allowed them to dominate the first generation of hybrid vehicle applications such as the Toyota Prius. However, as the market moves towards fully electric cars, it is likely that demand for nickel-metal hydride batteries will decrease as energy density becomes increasingly important. Nickel-metal hydride batteries have seen only limited use in grid-scale energy storage.
  4. Flow batteries – flow batteries are batteries in which rechargeability is provided by two chemical components dissolved in liquids separated by a membrane through which ion exchange occurs, generating an electric current. Key benefits of these systems are long cycle life, a fully scalable and flexibly laid-out design, and much higher power densities than lithium-ion batteries, with lower energy densities. This makes them suitable for applications where rapid charge and discharge over short time frames is needed, such as in frequency response services and demand-spike management. Vanadium redox flow batteries in particular are currently in use at a number of sites around the world, including a 6 MWh battery co-located with Huxley Hill wind farm in Australia, a 6 MWh battery at Tomari Wind Hills in Hokkaido, Japan and a 12 MWh flow battery which is under development as part of Sorne Hill wind farm in Ireland. As well as lower energy density, cost-effectiveness remains a major concern, though research into new iterations continues.
  5. Other contenders – other battery chemistries under development or already in use on a smaller scale include zinc-air and zinc-bromide (either of which could prove a cheap option in the long-term due to zinc's abundance) and molten-salt sodium-sulfur, which, although in the early stages of development, has seen several hundred MWs of capacity deployed in Japan, including a 34 MW, 235 MWh project at a Japan Wind Development project in Aomori Prefecture. 

UK context

Grid-scale battery storage deployment around the world has been led by the US, Japan, Korea and Germany, but the UK is now waking up to the significant investment opportunities afforded by the technology. More than 25 MW of capacity has already been deployed in the UK, including over 35 stand-alone projects and a huge number of domestic and small-scale commercial installations. The largest projects include:
  • AES Kilroot Station in Northern Ireland, an announced 50 MW lithium-ion project, interconnected (of which more than 10 MW is already completed), focusing on augmenting intermittent renewable generation;
  • an innovative £18.4m, 6 MW/10 MWh battery storage facility at Leighton Buzzard in Bedfordshire owned by UK Power Networks (UKPN) (through operator Smarter Network Storage), which has been operational since late 2014, and as of December 2016 has provided more than 7,500 hours of reactive power to National Grid;
  • Orkney Storage Park Project, an operational 2 MW lithium-ion storage project aimed at reducing transmission network congestion;
  • a battery storage system under construction at the headquarters of logistics and warehousing company JB Wheaton in Somerset being trialled by E.ON in conjunction with vanadium redox flow battery manufacturer RedT, as part of a bid to understand the potential for improved commercial returns on solar PV installations;
  • a 1 MW Northern Isles New Energy Solution battery storage facility co-located with wind power in Lerwick, Shetlands, with a further 1 MW under construction;
  • a 2.5 MW, 5 MWh single device project in Darlington as part of Northern Powergrid's storage trial programme;
  • E.ON and Uniper’s 2 MW lithium-titanate demonstrator facility at Willenhall; and
  • Hazel Capital’s Noriker Staunch storage project, currently under construction, which benefits from a two-year firm frequency response contract in Newcastle-under-Lyme.

In a report on smart power in March 2016, the National Infrastructure Commission (NIC) has said that, if costs continue to fall as anticipated, up to 15,000 MWh of battery storage could feasibly be deployed in the UK by 2030.2  This figure could be even higher if the UK Government introduces additional incentivisation and regulatory support for the sector, particularly when used in co-location with renewable generation assets (discussed below). The NIC report further urged the UK Government to implement regulatory changes necessary to facilitate greater adoption of grid-scale battery storage as an essential building block of a smart grid for the UK.

While the UK's distribution network operators (DNOs) might seem an obvious fit to make use of battery storage in managing local network demand fluctuations, they are not permitted to own storage under current market rules. In its report in March 2016, the NIC called for the Department of Energy and Climate Change (a predecessor to the Department for Business, Energy and Industrial Strategy) and Ofgem (the gas and electricity markets regulator) to expedite work to modernise regulation of DNOs, allowing them to own and operate storage assets and be subject to similar dynamic management and collaboration duties to those that already apply to National Grid. Changes to DNO regulation could ultimately allow DNOs to become distributed systems operators (DSOs): actively managing generation, storage and demand on their networks in response to macro-objectives requested by National Grid. It is evident that one of the key beneficiaries of such a move will be the battery storage market, given its versatility in meeting the demands the new DSOs will be required to address.

In response to these regulatory issues, the UK Government launched a call for evidence in November 2016 focusing on the future role of battery storage in smart energy grids, the results of which are expected in Q2 2017.3  The changes likely to result from this call for evidence have the potential to significantly improve the bankability of battery storage projects in the UK (as discussed below).

Bankability issues

Major bankability issues to consider when assessing UK battery storage projects include the key issues outlined below.

Securing a revenue stream

In the UK, bankable battery storage projects are likely to target one (or, in most cases, several) of the following revenue streams:

Enhanced Frequency Response contracts

In July 2016 National Grid put out a technology-neutral invitation-to-tender for its Enhanced Frequency Response (EFR) scheme. The purpose of the EFR scheme is to maintain the grid at a frequency as close to 50 Hz as possible at all times, as a replacement for National Grid's previous, slower, Firm Frequency Response scheme. The EFR scheme requires full active power output within one second in response to deviations in the grid from the standard 50 Hz frequency, to prevent faults. The previous scheme's fastest participants, generally gas plants, provide reactive power with a delay of around ten seconds. Of 37 providers bidding to become part of the scheme, 34 were from battery storage assets. Winners, including 200 MW of battery storage projects, were announced in July 2016, and included EDF Energy Renewables' 49 MW at its West Burton power station in Nottinghamshire, Vattenfall's 22 MW at Pen y Cymoedd wind farm in South Wales and E.ON's 10 MW at its Blackburn Meadow CHP plant in Sheffield. Winning bids are to enter into a four-year contract for provision of EFR services, which is double the length of those previously awarded under the Firm Frequency Response scheme.

CM contracts

The most recent CM auction, the results of which were announced in December 2016, cleared at £22.50/kW, securing 52.4 GW of capacity from 2020 at a cost of around £1.2bn. Despite the UK Government's stated goal of incentivising the development of new, large-scale gas turbine plants, none won contracts in the auction (while two new smaller gas plants were awarded contracts, both were extensions/rebuilds of existing plants). As part of the auction around 500 MW of new-build battery storage projects were awarded contracts. The 28 winning battery storage projects included four that already benefit from EFR contracts – the 10 MW Cleator project in Cumbria and 40 MW Glassenbury project in Kent being developed by Low Carbon, as well as the 49 MW West Burton project and the 10 MW Blackburn Meadows projects mentioned above. Several projects that were unsuccessful in the EFR process were also awarded CM contracts, including Centrica's 48 MW Roosecote project. The latest round saw battery storage projects winning the longer 15-year contracts for CM services for the first time, having won only four year contracts in previous iterations. This new longer-term, secure income stream for battery storage projects is a paradigm shift in terms of bankability. Future iterations of the CM mechanism are likely to see even greater interest from battery storage projects: Ofgem is currently consulting on splitting pumped storage from other storage technologies, which would mean battery storage would no longer be assumed to have pumped storage's (extremely high) availability and de-rating factor. Ofgem's recent decision to push forward with the removal of certain so-called "embedded benefits", which are seen to unfairly benefit distribution network connected diesel generators, may also inadvertently hurt the financial case for distribution network connected battery storage. Nevertheless, it is also likely that the UK Government will introduce measures to make it easier for battery storage embedded in demand-side response applications to participate in the CM (including the possibility of a minimum capacity in each auction which must be awarded to demand-side response providers) which may ameliorate in some instances the negative impact of the embedded benefits review.

Financial benefits of co-location with intermittent generation 

Co-locating renewable generation assets with onsite battery storage offers a number of obvious benefits, allowing for maximisation of generation output, particularly where grid connection constraints prove a major bottleneck at times of peak generation. For solar, tidal and, to a degree, wind projects, where generation is limited to specific periods, battery storage can also offer access to price arbitrage opportunities. Battery storage may be developed as an integral component of the generating plant, as a retrospective addition, or as a stand-alone project utilising shared land or grid connection, each with its own metering approach and commercial arrangements between the operators. In some instances, the benefits of co-location can even be sufficient to economically justify a project without any other revenue stream – in September 2016, Camborine Energy Storage announced a commercial-scale battery storage project (estimated at around 0.5MWh), using Tesla's Powerpack batteries in Europe, co-located with a solar PV site in Somerset, which is unsupported by revenue from an EFR or CM contract. Against the obvious advantages of co-located storage, developers must also consider the risk of how changes to a project may impact its entitlement to renewable benefits (see below).

Aggregation with demand-side response

Demand-side response aggregators, who seek to respond to National Grid's balancing needs by securing commitments from large baskets of diverse businesses across the country to reduce their power usage on demand (for example, a supermarket chain could slightly turn down its freezers or air conditioners for half an hour without major impact on its operations), can be hampered by the slow response times these approaches often have. Adding a relatively small amount of battery storage to an aggregation set-up can bridge the gap in response time for a much larger portfolio. National Grid has expressed a goal of a greatly increased role for demand-side response measures in balancing (targeting as much as 30-50 per cent of balancing capacity coming from demand-side response by 2020), meaning this area will likely see considerable development going forward. Demand-side response is an area where the UK is leading the field internationally, with a robust regulatory framework already in place.

Impact on existing renewable benefits

A major risk with retrospectively added co-location arrangements is the possibility that the changes to the project may imperil existing renewable benefits accruing to the generation assets, such as Renewables Obligation Certificate (ROC) accreditation. To date no co-located ROC and battery storage projects have been commissioned, although a number are under consideration including both integrated storage and retrospective additions of storage to commissioned plants. The key concern is that the existing legislation and guidance is not sufficiently clear on how co-located storage will be treated. It is clear that a material "behind the meter" modification to an existing ROC-accredited project will require an amendment to the accreditation. While Ofgem is considering an amendment, no ROCs will be issued and, typically, Ofgem will not pre-approve amendments to accreditation before the relevant works are complete. This leaves operators of existing, operational ROC accredited projects with the problem of both a gap in income while the amendment is considered and, more worryingly, the possibility that the existing accreditation could be invalidated if the amendment is rejected. Obviously, for existing project-financed facilities these risks are likely to be difficult to manage in a way that will satisfy lenders. It is hoped that these concerns will be addressed by the UK Government through clarification of regulations and the introduction of a pre-approval process for amendments, though in the absence of such clarification lenders may take some comfort from a growing number of precedent transactions.

A further issue can arise if the storage facility is an embedded part of the generating station (i.e. "behind the meter"). Because ROCs are issued only on the basis of metered (i.e. net) export, if the storage facility operates pre-meter, storage losses (which can be between 5 and 20 per cent depending on the battery chemistry) will reduce ROC accrual (or FIT receipts). This drawback may also be addressed by the UK Government through new regulations in 2017 to ensure all generated output is counted.

Impact on connection arrangements

The fact that co-location of intermittent generation with storage allows for a proportion of electricity generated to be stored (to be fed into the grid at times of non-generation) means that an intermittent generator with sufficient storage capacity can release electricity onto the grid in a manner more akin to a base-load generator with a lower installed capacity but higher availability factor. This can have benefits in terms of connection arrangements, as it will potentially allow for a much smaller grid connection for the project (reflecting the generator's average, rather than peak, output), and may even mean the generator can connect to a distribution network rather than the transmission network in some marginal cases.

Utilisation of battery storage in CfD projects

While the Contracts for Difference (CfD) standard terms in the 2015 CfD auction round do not expressly refer to battery storage, BEIS consulted in 2016 on proposals that, in the 2017 CfD auction round, co-located projects including storage should constitute separate Balancing Mechanism Units for the purposes of CfD metering. CfD payments would be calculated through metering at generation, not subsequent export from the storage device, avoiding the problem highlighted above whereby storage efficiency losses could decrease renewable benefit allotment.

In the response to this consultation, published in February 2017, the UK Government noted strong opposition to this proposal – respondents generally preferring the flexibility afforded by robust import/export metering or registering separate MPANs under the same BM Unit, rather than being forced to separate the BM Units entirely.4  These approaches, which require de-linking CfD settlement from BM Unit Metered Volume, would allow generators a number of benefits, including the ability to internally balance output, take advantage of qualifications for supply licence exemptions, and allow co-location of batteries with each generating unit (e.g. per wind turbine).

Unfortunately, due to the complexity of the proposals and need for further consultation, the UK Government declined, in the consultation response, to commit to a course of action which would fully address the identified issues. Instead, as a stop-gap measure, storage will be permitted to be registered in the same BM Unit as a CfD-awarded generating facility provided the generator can demonstrate to the Low Carbon Contracts Company (the CfD counterparty) that such storage is only used to store electricity generated by the CfD-awarded generating facility. While this is helpful for many co-located projects, it effectively prevents import of electricity from the grid which is needed for many of the more complex battery storage applications (for example, it precludes frequency response applications). A more comprehensive solution will hopefully be pursued after the 2017 allocation round. The consultation response did, however, adopt the flexible definition for "Electricity Storage" put forward by industry body The Electricity Storage Network.5  This is encouraging as it likely heralds widespread adoption of this definition in the regulatory regime (something that will hopefully be borne out in the response to the recent call for evidence on smart grids (see above)).

Double-charging, consumption levies and lack of legal status 

At present battery storage facilities are classified in certain circumstances for regulatory purposes as both electricity generators and consumers, and thus attract charges for use of the network and balancing system as well as consumption levies. Network charges for both import and export apply, some of which are designed to compensate the network for system stresses that battery storage may, perversely, be intended to mitigate. Finally as most grid-scale storage will purchase electricity from licensed suppliers, the effect of final consumption levies will be passed on to them through price although they are not strictly final consumers, including in respect of the Renewables Obligation, Contracts for Difference, CM and FIT regimes. The same applies in respect of the Climate Change Levy, though HMRC may waive CCL charges on a case by case basis. Clarifications of all of these regimes to remove double-charging and unfair levies are sorely needed, but are expected to be included in legislation changes to be introduced as part of the UK Government's response to the call for evidence on smart grids currently under way.

Generation licensing

The electricity licensing regime was designed at a time when pumped hydro, an iteration of existing hydropower generation stations, was the only material energy storage technology available. As a result, the regime classified pumped energy storage as a form of generation, and in the intervening years other forms of energy storage have automatically fallen within this classification (and resultant licensing requirements and obligations that follow from holding a generating licence), even though they may not be embedded in a generating plant. This will require developers to obtain a generating licence for non-embedded storage if the project capacity is over 100 MW, or a specific exemption if the project capacity is over 50 MW. Energy storage regulation, including its legal definition, clearly needs a rethink as well as separate regulatory provision, something the UK Government has acknowledged in its February 2017 response to its consultation on CfD contract changes. As with the charging methodology for use of the network, it is expected the UK Government will use the opportunity presented by its response to the 2016 call for evidence to provide some further clarity, though this may not amount to a commitment to pass primary legislation providing a comprehensive regulatory framework addressing battery storage's specific needs.

Planning consent

Because battery storage is not yet expressly provided for in electricity legislation there can be a lack of clarity when storage interacts with other areas of legislation and regulation, including the planning framework. For the time being, in the UK context, battery storage facilities are treated as a generating station for planning purposes, but this needs to be clarified in legislation (or ideally bespoke regulations for storage introduced) to avoid uncertainty.

Power purchase agreement considerations

New stand-alone battery storage projects or those to be co-located with a generation asset from its outset will need to ensure their power sales arrangements are sufficiently flexible to allow for any power shifting and attendant efficiency losses intended, as well as any alternative revenue streams they hope to realise from the storage. Where battery storage is retrospectively co-located with existing renewable generation, it is likely that the project's power purchase arrangements will need to be re-opened. In either case, areas likely to need significant attention will include arrangements for the import of electricity if this is envisaged for charging the batteries in some circumstances, reworking forecasting provisions to allow for a storage-augmented profile and removal of restrictions on (or a requirement to share revenue from) providing ancillary services or exporting additional power. Co-located projects may be willing to accept a greater share of imbalance risks as they will be able to mitigate them through use of the storage. Some of the major power offtakers, including Smartest, are even beginning to prepare standard form "supply and offtake" agreements in preparation for use with battery storage projects.

Power hedging

Having on-site battery storage with both an import and export capability opens up the possibility for projects to utilise physical electricity price hedging/trading. While this may provide the potential for a significant upside to the project, careful thought will need to be given to appropriate restrictions, thresholds and tolerances if this is not to create un-bankable risks.

Other considerations

As with power offtake arrangements, for retrospective addition of battery storage to existing renewables projects, existing financing and grid connection arrangements, property rights, and necessary consents for the project must be reviewed for any necessary changes or permissions, in dialogue with the relevant counterparts.


We are in the midst of a period of great change in the energy market, with significant developments in battery storage technologies and a shifting regulatory and revenue-support landscape. There are multiple roles presenting opportunities for battery storage investors, developers and lenders, with projects targeting different available revenue streams each with their own associated regulatory and commercial issues.

While uncertainty remains for generators hoping to retrofit battery storage into existing ROC-accredited projects, clarity on the interaction of CfD-awarded generating facilities and battery storage provided in the BEIS February 2017 consultation response is very welcome and the new regulatory position offers opportunities to develop or retrofit battery storage as an integral part of a typical renewable generation CfD project going forward.

Against a background of a growing sophistication in the regulatory framework and maturing technology, Ashurst envisages an increasing number of bankable opportunities based on stable government revenue streams for third-party funding of new stand-alone battery storage facilities and battery storage embedded in CfD-awarded renewable generation projects to arise in the latter half of 2017.



1. The Energyst – Centrica: Floodgates on battery storage investment to open in 2017 – 12 January 2017 (
2. National Infrastructure Commission Report, Smart Power, 4 March 2016 (
3. Department for Business, Energy,& Industrial Strategy, Call for evidence: A smart, flexible energy system, 10 November 2016 (
4. Department for Business, Energy,& Industrial Strategy – Results: Consultation on amending the CfD contract and regulations – 8 February 2017 (https:// file/589996/FINAL_-_Government_Response_to_the_CFD_Contract_ Changes_Consultation.pdf)
5. "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.  "Electricity Storage Facility" means a facility where Electricity Storage occurs or can occur and includes all assets performing or contributing to any such Electricity Storage."

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