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Strong and stable, or storing up trouble? The outlook for energy storage projects in the UK

While strength and stability have taken rhetorical centre stage in the run-up to the UK’s snap General Election on 8 June, the GB energy system faces radical uncertainty on a number of fronts at a time when its stakeholders need it least. So far, the main election focus on energy has inevitably been price caps for household gas and electricity bills. But once the excitements of the campaign and polling day are over, the new government will need to make up for lost time on some less potentially vote-grabbing issues that are central to the continued health of the GB energy sector. None of these is more pressing than how to respond to the possibilities opened up by energy storage technology.

This post will summarise the benefits of energy storage as an enabler of system flexibility, look at the technology options and market factors in play and consider both some of the practical issues faced by developers and the regulatory challenges that – General Election and Brexit notwithstanding – urgently need to be addressed by the government and/or the sector regulator Ofgem.

Benefits of energy storage

The most widely cited benefit of energy storage is the ability to address the intermittency challenge of renewable sources. For more than 100 years, the general lack of bulk power storage in the GB electricity system (other than a small amount of pumped hydro capacity) did not matter. Fluctuations in demand could easily be met by adjusting the amount of power produced by centralised fossil fuel plant that generally had fairly high utilisation rates. But in a power industry transformed by the rise of wind and solar technology, things are different. As a greater proportion of the generating mix is made up of technologies that cannot be turned on and off at will, often in areas where grid capacity is limited, storage offers the possibility that large amounts of power could be consumed hours or days after it is generated, reducing the otherwise inevitable mismatch between consumers’ demands for electricity and the times when the sun is out, the wind is blowing or the waves are in motion.

In a world that increasingly wants to use low carbon sources of electricity which are inherently less easy to match to fluctuations in demand than fossil fuelled generation, storage reintroduces an important element of flexibility. More specific advantages of energy storage range across value chain.

  • For generators, power generated at times of low demand (or when system congestion makes export impossible) can be stored and sold (more) profitably when demand is high, exploiting opportunities for arbitrage in the wholesale market and potentially also earning higher revenues in balancing markets. But storage does not just help wind and solar power. It can also help plants using thermal technologies that work most efficiently operating as baseload (such as combined cycle gas turbines or nuclear plants), but which may not find it economic to sell all their power at the time it is generated. Even peaking plants can use storage to their advantage by avoiding the need to waste fuel in standby mode (using e.g. battery power to cover the period in which they start up in response to demand).
  • For transmission system operators and distribution network operators, energy storage can mitigate congestion, defer the need for investment in network reinforcement and help to maintain the system in balance and operating within its designated frequency parameters by providing a range of ancillary or balancing services such as frequency response.
  • For end users, particularly those with some capacity to generate their own power, and providers of demand-side response services who aggregate end users into “virtual power plants”, energy storage can increase household or business self-consumption rates. And in a world of tariffs differentiated by time of use (enabled by smart metering), storage opens up the possibility of retail-level arbitrage or peak shaving: buying power when it is cheaper (because not many people want it) and storing it for use it at times when it would be more expensive to get it from the grid (because everybody wants to use it).

What could all that mean in practice? Estimates in National Grid’s Future Energy Scenarios 2016 suggest that over the next 25 years, deployment of storage in the UK could grow at least as rapidly as deployment of renewables has grown over the last 20 years. Also in 2016 the Carbon Trust and Imperial College London published a study that modelled the implementation of storage and other flexible technologies across the electricity system, and showed projected savings of between £17 billion and £40 billion between now and 2050. In a consultation published in May 2017, distribution network operator Western Power Distribution (WPD) invited comment on its proposed planning assumptions for the growth of storage in GB from its current capacity of 2.7 GW (all pumped hydro plants): these are a “low growth” scenario that anticipates 4-5 GW (6-15 GWh) by 2030 and a “high growth” scenario of 10-12 GW (24-44 GWh) by that date. Growth of storage at that higher rate would see it outstripping or close to matching current government estimates for the development of new gas-fired or nuclear generation, or new interconnection capacity over the same period. (Although it should be noted that the government’s own projections for the growth of storage are more in line with WPD’s low growth scenario: see this helpful analysis by Carbon Brief.)

Technology options

As is the case in Europe and the rest of the world, energy storage in the UK is currently mostly supplied by pumped hydropower plants, which account for almost all storage capacity and are connected to the transmission system. Until very recently, the much less frequently deployed technique of compressed air energy storage (CAES) was the only other commercially available technology for large-scale electricity storage. The two technologies are similar in that both use cheap electricity to put a readily available fluid (water or air) into a state (up a mountain or under pressure) from which it can be released so as to flow through a turbine and generate power. They differ in that pumped hydro requires a specific mountainous topography, whereas CAES can use a variety of geologies (including salt caverns, depleted oil and gas fields and underground aquifers).

But it is batteries that are currently attracting the keenest investor interest in storage. There are many different battery technologies competing for investment and market penetration. Those based on sodium nickel chloride or sodium sulphur have made advances, but most storage attention surrounds batteries based on lithium-ion structures, also the battery of choice for the electric car industry, where competition has driven down costs. Just before the General Election got under way, the Department of Business, Energy and Industrial Strategy (BEIS) announced £246 million of funding for the development and manufacture of batteries for electric vehicles. Electric car batteries need to be able to deliver a surge of power far more rapidly than those deployed in the wider power sector: in Germany, car manufacturers are already exploring the use of electric car batteries that no longer up to automotive specifications in grid-based applications. In the North East of England, distribution network company Northern Powergrid is collaborating with Nissan to look at how integration of electric vehicles can improve network capacity, rather than just placing increased demands on the grid.

The cost of batteries has come down because of improvements in both battery chemistry and manufacturing processes, as well as the economies of scale associated with higher manufacturing volumes such as with Tesla and Panasonic’s new battery Gigafactory in Nevada. Underlining rising global expectations about low cost and set-up time for battery production, in March 2017 Tesla’s Elon Musk offered to build a 100 MWh battery plant in Australia within 100 days, or to give the system away for free if delivery took any longer.

Batteries are ideally suited to many applications, but they also have some drawbacks. They are less good at providing sustained levels of power over long periods of discharge, and on a really large scale, than CAES or pumped hydro. The non-battery technologies also have other selling points. For example, CAES also has a unique ability, when combined with a combined cycle gas turbine, to reduce the amount of fuel it uses by at least a third. Given the likelihood that the UK power system will continue to need a significant amount of new large-scale gas fired plant, even as it decarbonises, and given the current slow development of carbon capture and storage technology, the potential reduction in both the costs and the carbon footprint of new gas-fired power that CAES offers is well worth consideration by both developers and government. Finally, as regards future alternative technology options, hydrogen storage and fuel cells are the subject of significant research efforts and funding. Most enticing from a decarbonisation perspective, is the prospect of electrolysing water with electricity generated from renewables to produce “green hydrogen”, which can then be used to generate clean power with the same level of flexibility as methane is at present.

Models and market factors

In the abstract, it might be thought that energy storage projects could be categorised into five basic business models:

  • integrated generator services: storage as a dedicated means of time-shifting the export of power generated from specific generating plants (renewable, nuclear or conventional), with which the storage facility may or may not be co-located, and so optimising the marketing of their power (and in some cases, where there are grid constraints, enabling more power to be generated, and ultimately exported, than would otherwise be the case);
  • system operator services: providing frequency response and other ancillary or balancing services to National Grid in its role as System Operator (and potentially, in the future, to a distribution system operator that is required to maintain balance at distribution level): a distinction can be made between “reserve” and “response” services, the latter involving very quick reaction to instructions designed to ensure frequency or voltage control;
  • network investment: enabling distribution networks to operate more efficiently and economically, for example by avoiding the need for conventional network reinforcement. This was notably successfully demonstrated by the 6 MW battery at Leighton Buzzard built by UK Power Networks (UKPN). The results of WPD’s Project FALCON were a little more equivocal, but it is trying again, using Tesla batteries to test a range of applications at sites in the South West, South Wales and the East Midlands);
  • merchant model: a standalone storage facility making the most of opportunities to buy power at low prices and sell it at high prices, with no tie to particular generators, and perhaps underpinned by Capacity Market payments (see further below);
  • “behind the meter”: enabling consumers to reduce their energy costs (retail level arbitrage or peak shaving, as noted above, as well as maximising use of on-site generation where this is cheaper than electricity from the grid).

These models are far from being mutually exclusive. Indeed, at present, they are best thought of as simply representing different categories of potential revenue streams: the majority of storage projects will need to access more than one of these streams in order to be viable. Some will opt to do so through contracts with an aggregator, for whom a relationship with generation or consumption sites with storage, particularly if they have a degree of operational control over the storage facility, offers an additional dimension of flexibility.

In the short term, the largest revenue opportunity may be the provision of grid services. The need for a fast response to control frequency variations is likely to increase in the future as a result of the loss of coal-fired plant from the system.

Growing interest in energy storage also owes much to the decline in the UK greenfield renewables market, with the push factor of the removal or drastic reduction of subsidies previously available for new renewable energy projects and the pull factor of the battery revolution. According to a report published in May 2017 by SmartestEnergy, an average of 275 solar, wind and other renewable projects were completed in each quarter between 2013 and the last quarter of 2016, when the figure plummeted to 38. Only 21 renewable projects were completed in the first quarter of 2017.

So why, when UKPN, for example, report that between September 2015 and December 2016 they processed connection applications from 600 prospective storage providers for 12 GW of capacity, is the amount of battery capacity so far connected only in the tens of MW?

Tenders and auctions

It may help to begin by looking at another very specific factor that drove this extraordinary level of interest in a technology that had been so little deployed to date. This was National Grid’s first Enhanced Frequency Response (EFR) tender, which took place in August 2016. A survey by SmartestEnergy, carried out just before the results of the tender were announced, found that 70 percent of respondents intending to develop battery projects in the near future were anticipating that ancillary services would be their main source of revenue.

National Grid were aiming to procure 200 MW of very fast response services. Although “technology neutral”, the tender was presented as an opportunity for battery storage providers and as expected, storage, and specifically batteries, dominated. All but three of the 64 assets underlying the 223 bids from 37 providers were battery units. Perhaps less expected were the prices of the winning bids: some as low as £7/MWh and averaging £9.44/MWh. The weighted price of all bids was £20.20/MWh.

This highly competitive tender gave the UK energy storage market a £65 million boost. The pattern of bids suggested that alongside renewables developers and aggregators, some existing utilities are keen to establish themselves in the storage market, and are prepared to leverage their lower cost of capital and accept a low price in order to establish a first mover advantage.

Independent developers who regard storage as a key future market might also have been bullish in their calculations of long-term income while accepting lower revenues in the near term to compete in a crowded arena. For all bidders, one of the key attractions was the EFR contract’s four-year term, which makes a better fit with their expectations of how long it will take to recoup their initial investment than the shorter duration of most of National Grid’s other contracts for balancing / ancillary services.

Aspiring battery storage providers also responded enthusiastically to the regular four year ahead (T-4) Capacity Market (CM) auction when it took place for the third time in December 2016. To judge from the Register for the T-4 2016 auction, some 120 battery projects, with over 2 GW of capacity between them, were put forward for prequalification in this auction. (This assumes that all the new build capacity market units (CMUs) described as made up of “storage units” and not obviously forming part of pumped hydro facilities were battery-based.) Although almost two-thirds of these proposed CMUs are described on the relevant CM register as either “not prequalified” or “rejected”, of the remaining 33 battery projects, no fewer than 31 projects, representing over 500 MW of capacity between them, went on to win capacity agreements in the auction.

There are a number of points to be made in connection with these results.

  • Taking the CM and EFR together, the range of parties interested in batteries is noteworthy, as is the diversity of motivations they may have for their interest.  It includes grid system operators (UKPN), utilities (EDF Energy, Engie, E.ON, Centrica), renewables developers (RES, Element Power, Push Energy, Belectric), storage operators, aggregators / demand side response providers (KiWi Power, Limejump, Open Energi) and end-users, as well as new players who seem to be particularly focused on storage (Camborne Energy Storage, Statera Energy, Grid Battery Storage).
  • Developers of battery projects are evidently confident that the periods during which they may be called on to meet their obligations to provide capacity by National Grid will not exceed the length of time during which they can continuously discharge their batteries – in other words, that the technical parameters of their equipment do not put them at an unacceptable risk of incurring penalties for non-delivery under the CM Rules: a point that some had questioned.
  • The CM Rules are stricter than those of the EFR tender as regards requiring projects to have planning permission, grid connection and land rights in place as a condition of participating in the auction process. This is presumably one reason why fewer battery projects ended up qualifying to compete in the T-4 auction as compared with the EFR tender.
  • For batteries linked to renewable electricity generation schemes that benefit from renewables subsidy schemes such as the Renewables Obligation (RO), the EFR tender was an option, but the CM was not, since CM Rules prohibit the doubling up of CM and renewables support. So, for example, the 22 MW of batteries to be installed at Vattenfall’s 221 MW RO-accredited Pen-y-Cymoedd wind farm was successful in the EFR tender but would presumably not have been eligible to compete in the CM.
  • Accordingly, CM projects tend to be designed to operate quite independently of any renewable generating capacity with which they happen to share a grid connection. But some of these projects are located on farms that might have hosted large solar arrays when subsidies were readily available for them. Green Hedge, four of whose projects were successful in the T-4 2016 CM auction, has even developed a battery-based storage package called The Energy BarnTM. Others CM storage projects are located on the kind of industrial site that might otherwise be hosting a small gas-fired peaking plant. UK Power Reserve (as UK Energy Reserve), which has been very successful with such plants in all the T-4 auctions to date, won CM support for batteries at 12 such locations.
  • The Capacity Market may be less lucrative than EFR, measured on a per MW basis, but it offers the prospect of even longer contracts: up to 15 years for new build projects.
  • Batteries are still a fairly new technology. The clearing price of Capacity Market auctions has so far been set by small-scale gas- or diesel-fired generating units using well established technology. In a T-4 auction, the CMUs, by definition, do not have to be delivering capacity until four years later – although the Capacity Market Rules oblige successful bidders to enter into contracts for their equipment, and reach financial close, within 16 months of the auction results being announced. Other things being equal (which they may not be: see next bullet), it will clearly be advantageous to developers if they can arrange that the prices they pay for their batteries are closer to those prevailing in 2020 than in 2016. It has been pointed out that although internationally, battery prices may have fallen by up to 24 percent in 2016, the depreciation of Sterling over the same period means that the full benefit of these cost reductions may not yet be accessible to UK developers.
  • The proportion of prequalified battery-based CMUs that were successful in the T-4 2016 CM auction was remarkably high. But may not have been basing their financial models solely or even primarily on CM revenues. In addition to EFR and other National Grid ancillary services, such as Short Term Operating Reserve or Fast Reserve, and possible arbitrage revenues, it is likely that at least some projects were anticipating earning money by exporting power onto the distribution network during “Triad” periods. This “embedded benefit” would enable them to earn or share in the payments under the transmission charging regime that have been the main source of revenue for small-scale distributed generators bidding in the CM, enabling them to set the auction clearing price at a low level and prompting a re-evaluation of this aspect of transmission charges by Ofgem. From Ofgem’s March 2017 consultation on the subject, it looks as if these payments will be drastically scaled down over the period 2018 to 2020. This may give some developers a powerful incentive to deploy their batteries early (notwithstanding the potential cost savings of waiting until 2020 to do so) so as to benefit from this source of revenue while it lasts. Those who compete in subsequent CM auctions may find that the removal of this additional revenue leads to the CM auctions clearing at a higher price.
  • As with EFR, some developers may be out to buy first mover advantage, and most already have a portfolio of other assets and/or sources of revenue outside the CM. But what they are doing is not without risk, since the penalties for not delivering a CMU (£10,000, £15,000 or £35,000 / MW, depending on the circumstances) are substantial.
  • Meanwhile, a sure sign of the potential for batteries to disrupt the status quo can be seen in the fact that Scottish Power has proposed a change to the CM Rules that would apply a lower de-rating factor to batteries for CM purposes than to its own pumped hydro plant.

Finally, one other tender process, that took place for the first time in 2016, could point the way to another income stream for future projects. National Grid and distribution network operator Western Power Distribution co-operated to procure a new ancillary service of Demand Turn Up (DTU).

The idea is to increase demand for power, or reduce generation, at times when there is excess generation – typically overnight (in relation to wind) and on Summer weekends (in relation to solar). DTU is one of the services National Grid use to ensure that at such times there is sufficient “footroom” or “negative reserve”, defined as the “continuous requirement to have resources available on the system which can reduce their power output or increase their demand from the grid at short notice”.

National Grid reports that over the summer of 2016, the service was used 323 times, with “10,800 MWh called with an average utilisation price of £61.41/MWh”. The procurement process can take account of factors other than the utilisation and availability fees bid, notably location. Successful tenders in the 2017 procurement had utilisation fees as high as £75/MWh.

At present, the procurement process for DTU does not appear to allow for new storage projects to compete in DTU tenders, but once they have become established, they should be well placed to do so, given their ability to provide demand as well as generation. They could be paid by National Grid to soak up cheap renewable power when there is little other demand for it. If National Grid felt able to procure DTU or similar services further in advance of when they were to be delivered, the tenders could have the potential to provide a more direct stimulus to new storage projects.

Battery bonanza?

Those who have been successful in the EFR or CM processes can begin to “stack” revenues from a number of income streams. And the more revenues you already have, the more aggressively you can bid in future tenders (for example for other ancillary services) to supplement them.

But even if all the projects that were successful in the EFR and CM processes go ahead, they will still represent only a small fraction of those that have been given connection offers. Moreover, it looks as if the merchant and ancillary services models are the only ones making significant headway at present.  Why are we not seeing more storage projects integrated with renewables coming forward, for example? Why, to quote Tim Barrs, head of energy storage sales for British Gas, has battery storage “yet to achieve the widespread ‘bankable status’ that we saw with large-scale solar PV”?

Technology tends to become bankable when it has been deployed more often than batteries coupled with renewables have so far in GB. But even to make a business case to an equity investor, a renewables project with storage needs to show that over a reasonable timeframe the additional revenues that the storage enables the project to capture exceed the additional costs of installing the storage. What are these costs, over and above the costs of the batteries and associated equipment?  What does it take to add storage to an existing renewable generating project, or one for which development rights have already been acquired and other contractual arrangements entered into?

  • The configuration and behaviour of any storage facility co-located with subsidised renewable generation must not put the generator’s accreditation for renewable subsidies at risk because of e.g. a battery’s ability to absorb and re-export power from the grid that has not been generated by its associated renewable generating station. The location of meters is crucial here. According to the Solar Trade Association, only recently has Ofgem for the first time re-accredited a project under the RO after storage was added to it. While an application for re-accreditation is being considered, the issue of ROCs is suspended. Guidance has been promised which may facilitate re-accreditation for other sites. Presumably in this as in other matters, the approach for Feed-in Tariff (FIT) sites would follow the pattern set by the RO. For projects with existing Contracts for Difference (CfDs), there is no provision on energy storage. For those hoping to win a CfD in the 2017 allocation round, the government has made some changes to the contractual provisions following a consultation, but, as the government response to consultation makes clear, a number of issues still remain to be resolved.
  • An existing renewables project is also likely to have to obtain additional planning permission. There may be resistance to battery projects in some quarters. RES recently had to go to appeal to get permission for a 20 MW storage facility by an existing substation at Lookabootye after its application was refused by West Lothian Council. It will also be necessary to re-negotiate existing lease arrangements (or at least the rent payable under them), and additional cable easements may be required.
  • Unless it is proposed that the battery will take all its power from the renewable generating station (which is unlikely), it will be necessary to seek an increase in the import capacity of the project’s grid connection from the distribution network operators. Even if the developer does not require to be able to export any more power at any one time from the development as a whole, in order to charge the battery at a reasonable speed from the grid it will need a much larger import capacity than is normal for an ordinary renewable generating facility. The ease and costs of achieving this will vary depending on the position of the project relative to the transmission network. There may be grid reinforcement costs to pay for: UKPN has noted that there are few places on the network with the capacity to connect a typical storage unit without some reinforcement. They will also treat the addition of storage as a material change to an existing connection request for a project that has not yet been built, prompting the need for redesign and resulting in the project losing its place in the queue of connection applications.
  • A power purchase agreement (PPA) for a project with storage will need to address metering. For the purposes of the offtaker, output will either need to be measured on the grid side of the storage facility (the same may not be true of metering for renewable subsidy purposes), or an agreed factor will need to be applied to reflect power lost in the storage process. Secondly, in order to maximise the opportunities for arbitrage by time-shifting the export of its power, a project with storage may want more exposure to fluctuations in the wholesale market price, and even to imbalance price risk, than a traditional intermittent renewables project. The detail of how embedded benefits revenues are to be shared between generator and offtaker may also require to be adjusted if the addition of storage makes it more likely they will be captured.

For the moment, most renewables projects probably fall into one of two categories with regard to integrated storage.

  • On the one hand, there are those that are already established and receiving renewable generation subsidies, or which have been planned without storage and now simply need to commission as quickly as possible in order to secure a subsidy (for example, under RO grace period rules for onshore wind projects). For them, introducing storage into an existing project may be more trouble than it is worth for some or all of the reasons noted above. They have little incentive to deploy storage unless it is an economic way of reducing their exposure to loss of revenue as a result of grid constraints or to imbalance costs: these have been increasing following the reforms introduced by Ofgem in 2015 and will increase further as the second stage of those reforms is implemented in 2018, but for many renewable generators are a risk that is assumed by their offtakers.
  • On the other hand, for projects with no prospect of receiving renewable subsidies, it would appear that the cost of storage is not yet low enough, or the pattern of wholesale market prices sufficiently favourable to a business model built on  time-shifting and arbitrage to encourage extensive development of renewables + storage merchant model projects. If it was generally possible easily to earn back the costs of installing storage through the higher wholesale market revenues captured by – for example – time-shifting the export of power from a solar farm to periods when wholesale prices are higher than they are during peak solar generating hours, the volume and profile of successful storage + renewable projects in the CM and elsewhere would be different from what it now is.

However, battery costs will continue to fall, and wholesale prices are becoming “spikier”. It may only be a matter of time before GB’s utility-scale renewables sector, whose successful players have so far built their businesses on the predictable streams produced by RO and FIT subsidies, can get comfortable with business cases that depend more fundamentally on the accuracy of predictions about how the market, rather than the weather, will behave. Moreover, there is nothing to stop a storage facility co-located with a renewables project that has no renewable subsidy from earning a steady additional stream of income in the form of CM payments.

Arguably, the UK has missed a trick in not having adopted pump-priming incentives for combining storage with renewables, such as setting aside a part of the CfD budget for projects with integrated storage. But with the door apparently generally closed for the time being on any form of subsidy for large-scale onshore wind or solar schemes in most of GB, it is probably unrealistic to hope for any such approach to be taken in the near future.

Regulatory challenges

There are undoubtedly already significant commercial opportunities for some GB storage projects, but it does not feel as if the full power of storage to revolutionise the electricity market is about to be unleashed quite yet. This is perhaps not surprising.

Almost as eagerly awaited among those interested in storage as the results of the EFR tender was a long-promised BEIS / Ofgem Call for Evidence on how to enable a “smart, flexible energy system”, which was eventually published in November 2016. This Call for Evidence, the first of its kind, represented a significant step forward for the regulation of storage in the UK, but although it pays particular attention to storage and the barriers that storage operators may face it is not just “about” storage. It ultimately opens up questions about how well the current regulatory architecture, designed for a world of centralised and despatchable / baseload power generation, can serve an increasingly “decarbonised, distributed, digital” power sector without major reform. (At an EU level, the European Commission’s Clean Energy Package of November 2016 tries to answer some of these questions, and there is generally no shortage of thoughtful suggestions for reforming power markets, such as the recent Power 2.0 paper from UK think tank Policy Exchange, or the “Six Design Principles for the Power Markets of the Future” published by Michael Liebreich of Bloomberg New Energy Finance.)

However, whilst it is important to take a “whole system” approach, it would be unfortunate if the breadth of the issues raised by the Call for Evidence were to mean that there was any unnecessary delay in addressing the regulatory issues of most immediate concern to storage operators. Government and regulators have to start somewhere, and it is not unreasonable to start by trying to facilitate the deployment of storage since it could facilitate so many other potentially positive developments in the industry.

On 25 April Ofgem revealed that it had received 240 responses to the Call for Evidence, with around 150 responses commenting on energy storage. Barriers to the development of storage identified by respondents include the need for a definition of energy storage, clarity on the regulatory treatment of storage, and options for licensing. The response from the Energy Storage Network (ESN) offers a good insight into many of the issues of most direct concern to storage operators. Some of the other respondents who commented on storage also demonstrated an appetite for fundamental reform of network charging (described by one as “probably not fit for purpose in its current form”) and for significant shifts in the role of distribution network operators.

Interest in a definition of energy storage is unsurprising. It is arguably hard to make any regulatory provision about something if you have not defined it. But at the same time, the Institution of Engineering and Technology may well be correct when it says in its response to the Call for Evidence: “lack of a definition is not a barrier in itself…as the measures are developed to address the barriers to storage, it will become clear whether a formal definition is required and at what level…agreeing a definition should be an output of regulatory reform, not an input.”. In other words, how you define something for regulatory purposes – particularly if that thing can take a number of different forms and operate in a number of different ways – will depend in part on what rules you want to make about it.

Under current rules, energy storage facilities end up being classified, somewhat by default, as a generation activity – even though their characteristic activity does not add to the total amount of power on the system. But because storage units also draw power from the grid, they find themselves having to pay two sets of network charges – on both the import and the export – even though they are only “warehousing” the power rather than using it. Both these features of the current regulatory framework are strongly argued against by a variety of respondents to the Call for Evidence.

Treating storage as generation complicates the position for distribution network operators wishing to own storage assets. Under the current unbundling rules (which are EU-law based, but fully reflect GB policy as well), generation and network activities must be kept in separate corporate compartments. These rules are designed to prevent network operators from favouring their own sources of generation (or retail activities). The issue is potentially more acute when you have a storage asset forming part of the network company’s infrastructure and regulated asset base, but having the ability to trade on the wholesale power and ancillary services markets in its own right as well as to affect the position of other network users (by mitigating or aggravating constraints). UKPN considers that the approach it has adopted with its large battery project could provide a way around this problem for others as well – essentially distinguishing the entity that owns the asset from the entity responsible for its trading activity on the market. However, such an arrangement is not without costs and complexity, both for those involved to set up and for the regulator to monitor. The ESN has also made proposals in its response to the Call for Evidence about the conditions under which distribution network operators should be permitted to operate storage facilities.

It may be that the most useful contribution that transmission and distribution network operators could make to the development of storage would be to determine as part of their multi-year rolling network planning processes where it would be most beneficial in system terms for new storage capacity of one kind or another to be located. But the underlying question is whether at least some storage projects should be treated more as network schemes with fixed OFTO or CATO-like rates of return rather than being regarded as part of the competitive sector of the market along with generation and supply. (Similar concerns about the status of US network-based storage projects, admittedly in a slightly different regulatory environment, have been addressed by the Federal Energy Regulatory Commission in a recent policy statement and notice of proposed rulemaking.)

If storage is not to be treated as generation or necessarily part of a network (and required to hold a generation licence where no relevant exemption applies), what is it? Should it be recognised as a new kind of function within the electricity market? In which case, the natural approach under the GB regulatory regime would be to require storage operators to be licensed as such (again, subject to any statutory exemptions). That would require primary legislation (i.e. an Act of Parliament) to achieve, at a time when Parliamentary time may be at a premium because of Brexit – and then there would need to be drafting of and consultation on licence conditions and no doubt also numerous consequential changes to the various industry-wide codes and agreements.

The ESN’s Call for Evidence response has some helpful suggestions as to what a licensing regime for storage might look like. But is the licensing model is a red herring in this context? After all, the parallel GB regulatory regime for downstream gas includes no requirement for those wishing to operate an onshore gas storage facility to hold a licence to do so under the Gas Act 1986. And it is entirely possible to trade electricity on the GB wholesale markets (a key activity for storage facilities), without holding a licence under the Electricity Act 1989 (or even engaging in an activity requiring such a licence but benefiting from an exemption from the requirement to hold a licence).

As for some of the current financial disadvantages facing storage, it is encouraging that in consulting on its Targeted Charging Review of various aspects of network charging in March 2017, Ofgem provisionally announced its view that some double charging of storage should be ended. It consulted on a number of changes that, taken together, should have the effect of ensuring that “storage is not an undue disadvantage relative to others providing the same or similar services”. However, although welcome, these Ofgem proposals so far only cover the treatment of the “residual” (larger) element of transmission network charges for demand (applicable to distribution-connected projects), in respect of storage units co-located with generation. It remains to be seen whether – and if so, what – action will be taken to deal with other problems in this area, such the payment of the “final consumption” levies that recover the costs of e.g. the RO and FIT schemes by both the storage provider and the consumer on the same electricity when a storage operator buys that electricity from a licensed supplier. Storage operators can at present only avoid this cost disadvantage if they acquire a generation licence, which does not seem a particularly rational basis for discriminating between them in this context.

Speaking in March, the head of smart energy policy at BEIS, Beth Chaudhary, said that ending the double counting of storage “might require primary legislation”, adding that Brexit has made the progress of such legislation “difficult at the moment”. The General Election has only added to concerns of momentum loss, a sense of “circling the landing strip” in the words of the Renewable Energy Association’s chief executive, Dr Nina Skorupska.

“The revolution will not be televised”…but it probably needs to be regulated

What is the storage revolution? Storage will not turn the electricity industry into a normal commodity market, like oil, overnight – or indeed ever. We will still have to balance the grid. As before, what is being exported onto the grid will need to match what is being imported from it at any given moment. It’s just that storage will provide an additional source of power to be exported onto the grid (which was generated at an earlier time) and it will also facilitate more balancing actions by those on the demand side where they have access to it. It is also likely that increased use of micro grids, with the ability to operate in “island mode” as well as interconnected with the public grid, will result in the public grid handling a smaller proportion of the power being generated and consumed at any given time.

Of course, one could look at this and say: “Fine, but what’s the hurry?”. The UK developed a renewables industry when it was still a relatively new and expensive thing to do. Thanks to the efforts made by the UK and others, renewables are now both “mainstream” and relatively cheap. Those countries that are only starting to develop sizeable renewable projects now are reaping the benefit of the cost reductions achieved by the early adopters. Would it be such a bad thing if a GB storage revolution was delayed for a year or two while other markets experiment with the technology and help it to scale up, reducing the costs that UK businesses and consumers will pay for its ultimate adoption in the UK?

After all, we have to be realistic about the number of large and difficult issues the UK government and regulators can be expected to focus on and take forward at once. Is it not more important, for example, to reach agreement with the rest of the EU on a satisfactory set of substitute arrangements for the legal mechanisms that currently govern the UK’s trade in electricity and gas with Continental Europe (and the Republic of Ireland)? In addition, the General Election manifestos of each party prioritise other contentious areas of energy policy for action, such as facilitating fracking and reducing the level of household energy bills.

We do not deny the importance of these other issues, and BEIS and Ofgem resources are, of course, finite, but we would argue that storage and the complex of “flexibility” issues to which it is central should be high on the policy agenda after 8 June in any event.

  • GB distribution network operators have already done lot of valuable work on storage, much of it funded by various Ofgem initiatives (notably the Innovation Funding Incentive, Network Innovation Allowance and Low Carbon Networks funding). This has generated a body of published learning on the subject which continues to be added to and which it would be a pity not to capitalise on as quickly as possible.
  • Depending (at least in part) on the outcome of Brexit, we may find ourselves either benefiting from significantly more interconnection with Continental European power markets, or becoming more of a “power island” compared with the rest of Europe. In either case, a strong storage sector will be an advantage. Storage can magnify the benefits of interconnection but it would also help us to optimise the use of our own generating resources if our ability to supplement them (or export their output) through physical links to other markets was limited.
  • The UK has in some respects led the world on power market reform.  We have complex, competitive markets and clever companies that have learnt how to operate in them. Looking at storage from an industrial strategy point of view, the UK is may not make its fortune after by the mass manufacture of batteries for the rest of the world, but the potential for export earnings from some of the higher value components of storage facilities, and the expertise to deploy them to maximum effect, should not be neglected.
  • On the other hand, if the UK wants to maintain its position as an attractive destination for investment in electricity projects, it needs to show that it has a coherent regulatory approach to storage, both because storage will increasingly become an asset class in its own right and because sophisticated investors in UK generation, networks or demand side assets will increasingly want to know that this is the case before committing to finance them.
  • As the Call for Evidence and the other attempts to address the challenges of future power markets referred to above make clear, everything is connected. There is, arguably, not very far that you can or should move forward on any aspect of generation or other electricity sector policy without forming a view on storage and how to facilitate it further.
  • Finally, because some of the policy and regulatory issues are hard and resources to address them are finite, this will all take time, so that with luck, the regulatory framework will have been optimised by about the same time as the price reductions stimulated by demand from the US and other forward-thinking jurisdictions have started to kick in.

Almost whatever problem you are looking at, whether as a regulator or a commercial operator in the GB power sector, it is worth considering carefully whether and how storage could help to solve it. Storage has the potential, as noted above, to change the ways that those at each level in the electricity value chain operate, and with the shift to more renewables and decentralised generation, it has a significant part to play in making future electricity markets “strong and stable”. The “trouble” alluded to in the title of this post is change either happening faster than politicians and regulators can keep pace with, or innovation being stifled by the lack of regulatory adaptation as they find it too difficult to address the challenges it poses when faced with other and apparently more urgent priorities. Because the ways in which generators, transmission and distribution network operators, retailers and end users interact with each other is so much a function of existing regulation of one kind or another, it is very hard to imagine storage reaching its full potential without significant regulatory change. These changes will take time to get right, but since ultimately an electricity sector that makes full use of the potential of storage should be cheaper, more secure and more environmentally sustainable than one that does not, there should be no delay in identifying and pursuing them.

 

 

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Strong and stable, or storing up trouble? The outlook for energy storage projects in the UK

UK onshore wind subsidies: not dead yet

A vote in the House of Lords on 21 October 2015 has, for the moment at least, derailed the Government’s proposals to prevent new onshore wind farms commissioned after 31 March 2016 from being subsidised under the Renewables Obligation (RO).

Readers of our earlier posts on this subject (see here and here) will recall that in June 2015 Government said that its proposals would form part of the current Energy Bill.  In July, “grace period” arrangements were promised for those projects with planning permission, grid connection agreements and land rights by 18 June 2015.  On 8 October, Government amendments to the Bill, setting out the details of grace period relief, were  published.  They covered a somewhat broader range of cases than just the “planning / grid / land rights” one.  After a Committee debate on 14 October 2015 in which Lord Wallace of Tankerness and others identified a range of scenarios where they felt projects would, unfairly, not benefit from the grace period amendments, Lord Bourne, for the Government, withdrew the amendments to consider them further.

Before the debate at Report stage on 21 October, Government re-tabled its amendments, virtually unchanged, and Opposition Peers tabled a number of others, including one that simply removed clause 66 (the early closure provision) from the Bill altogether.  This amendment was passed, by 242 votes to 190.

What is going on, and what (so far as we can tell) happens next?

  • Ministers have suggested that in voting to remove clause 66, Peers were flouting the “Salisbury convention” – i.e. the principle that the unelected House should not thwart measures that have appeared in the election manifesto of an incoming Government.  The Opposition response to this is that the Conservatives’ General Election pledge to “end any new public subsidy” for onshore wind was one thing (which might, for example, equate to removal of onshore wind from the list of technologies eligible to compete for Contracts for Difference (CfDs)); but bringing forward the closure of the RO (an existing subsidy) is another thing altogether.

 

  • The Opposition stress that they are not opposing the phasing out of onshore wind subsidies per se – rather, they object to what they see as the Government’s failure to provide details of the proposed grace period arrangements soon enough for them to be properly scrutinised and amended, and to the fact they do not cover various categories of projects whose exclusion from the RO seems to them to be unfair.  It is also alleged that the average savings to Bill payers (30p per household annually) from early closure are outweighed by the lost investments on the part of the industry (over £300 million).

 

  • Some of the “hard luck cases” cited might not have achieved RO accreditation even under the existing, pre-18 June position on RO closure.  Others that it is said may be unfairly treated by the 8 October amendments include projects where a local authority decided to grant planning permission before 18 June but the mitigation arrangements under a “section 106” (England and Wales) or “section 75” (Scotland) agreement were not yet signed off; cases where the developer gave the local planning authority longer than the statutory minimum before treating its silence as a “deemed refusal” of planning permission and challenging it; and cases where a project essentially had a grid connection agreement for some time prior to 18 June but temporarily lost it before that date.

 

  • Lord Bourne may win a prize for Parliamentary understatement when he said, towards the end of proceedings: “The debate has exhibited a clear difference of position in relation to onshore wind.”

 

  • For the moment, the Bill does not provide for early closure of the RO to new onshore wind projects.

 

  • In order to carry out its policy, the Government will have to muster more support at Third Reading in the Lords, or reintroduce the early closure provision in the Commons, where its MPs are likely to be easier to whip.  In the latter case, the provision would then have to return to the Lords for consideration, and could go through more than one round of “ping pong” between the two Houses – with the wind industry (or at least many projects) in suspense in the meantime.

 

  • Unless the Prime Minister really intends to create enough new Peers to guarantee passage through the Lords of the RO closure provisions in the form the Government wants (as appeared to be suggested in connection with the parallel Lords rebellion on cutting tax credits for working families), it looks as if Government needs to secure agreement on a package of grace period amendments that Opposition Peers are content to accept.

 

  • The Parliament Act 1911 enables the Government effectively to bypass the House of Lords in certain circumstances.  But it is unlikely to be of any use to the Government on this occasion, since its timescales would not allow the Bill to be enacted until well after 31 March 2016 – and possibly not (or only a few weeks) before the general RO closure date of 31 March 2017.

Finally, it is worth noting that the vote on clause 66 was one of two Government defeats during the Report stage debate on the Bill.  Peers also voted in an Opposition amendment that would change the basis on which the UK’s carbon budgets are set under the Climate Change Act 2008 – probably with the effect of making them harder to meet.  This more technical and, on the face of it, less politically exciting change is in part a reaction to the Government’s confirmation that it will not be setting a decarbonisation target for the power sector (whose emissions are said not to be counted in carbon budget setting because they fall within the EU Emissions Trading Scheme).  In the longer term, it may – if it survives – have even more far-reaching effects than those of the removal of clause 66.

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UK onshore wind subsidies: not dead yet

Grace periods for early closure of Renewables Obligation support for onshore wind

On 8 October 2015, the UK Government’s Department of Energy and Climate Change (DECC) set out its detailed proposals for mitigating the impact of the proposed early closure of the Renewables Obligation (RO) to new onshore wind projects from 1 April 2016. The provisions now set out in a series of proposed amendments to the relevant part of the Energy Bill, which are to be debated by the House of Lords on 14 October 2015, go a little beyond what DECC first put forward at the start of its period of “engagement” with the industry at the start of July 2015.

The original grace period proposal was relatively simple, and based on the “significant investment grace period” for >5MW solar PV projects. An onshore project would be able to achieve RO accreditation if it commissioned and applied for accreditation after 31 March 2016 but before 1 April in 2017, provided that, as at 18 June 2015 (the date of DECC’s announcement about the proposed early closure) it had planning permission, an accepted offer of connection to the transmission or distribution network, and sufficient rights over the land where it was to be situated – e.g. in the form of a lease, option, agreement for lease or exclusivity agreement.

The proposals set out in the 8 October amendments are more generous, but also more complex. They consist primarily of the insertion of a new run of sections in the RO provisions of the Electricity Act 1989 and their effect is summarised in the table below.

Section of Act (as it would be amended) Date wind farm / relevant additional capacity  is accredited Applicable grace period conditions to be satisfied in order to obtain accreditation
32LD On or before 31 March 2016 No need for grace period
32LE Between 1 April 2016 and 31 March 2017 Grid and radar delay condition – i.e. that:

In respect of either grid connection or radar mitigation works relating to the wind farm / additional capacity on or before the date when Ofgem decided to accredit it, Ofgem has received from the operator:

(a) evidence of an agreement to carry out the works in respect of the wind farm / additional capacity;

(b) document from the network operator / radar agreement counterparty estimating completion on or before the primary date (see below);

(c) letter from the network operator / radar agreement counterparty confirming that the works were completed later than planned, and that this was not due to any breach by the wind farm developer; and

(d) declaration by the operator that to the best of its knowledge and belief, the wind farm / additional capacity would have been commissioned / formed part of the wind farm before the primary date if the works had been completed by that date.

For the purposes of section 32LE, the primary date is 31 March 2016.

32LF On or before 31 March 2017 Approved development condition – i.e. that the accreditation application is accompanied by the following as regards planning, grid connection and land rights.

Planning

One of the following:

(a) evidence that planning permission (or s. 36 consent / development consent under the Planning Act 2008) was granted on or before 18 June 2015;

(b) evidence that planning permission (or s. 36 consent / development consent under the Planning Act 2008) was refused on or before 18 June 2015 but granted after that date following an appeal or judicial review;

(c) evidence that an application for planning permission was made to the local planning authority on or before 18 June 2015; the authority failed to determine or decline to determine application, or refer it to Ministers, within the statutory period; the application was not referred to Ministers; and the application was granted after 18 June 2015 following an appeal; or

(d) a declaration that to the best of the operator’s knowledge and belief, planning permission is not required for the wind farm / additional capacity,

and that any conditions as to the time for commencement of development in the relevant planning permission have been complied with.

Grid connection

One of the following:

(a) a copy of an offer from a licensed network operator made on or before 18 June 2015 to carry out grid works in relation to the wind farm / additional capacity and evidence that the offer was accepted on or before that date; or

(b) a declaration by the operator that to the best of its knowledge and belief no grid works are required to commission the wind farm / additional capacity.

Land rights

A declaration that to the best of the operator’s knowledge and belief a developer of the wind farm or additional capacity or a person connected with it in within the meaning of s. 1122 Corporation Tax Act 2010:

(a) was an owner or lessee of the land where the wind farm / additional capacity is to be situated;

(b) had entered into an agreement to lease that land;

(c) had an option to purchase or lease that land; or

(d) was a party to an agreement by the owner or lessee of the land not to permit any person other than those identified in the agreement to construct a wind farm there.

32LG Between 1 April 2017 and 31 March 2018

 

Approved development condition

and

Grid and radar delay condition – noting that:

Documentary requirements are as described in relation to section 32LE, but

For the purposes of section 32LG, the primary date is 31 March 2017.

32LH Between 1 April 2017 and 31 December 2017

 

Approved development condition

and

Investment freezing condition – i.e. that the accreditation application is accompanied by the following documents:

(a) a declaration from the operator that, to the best of its knowledge and belief, as at 1 May 2016:

(i) it required funding from a recognised lender (a provider of debt finance with an investment grade credit rating) before the wind farm / additional capacity could be commissioned / added;

(ii) the recognised lender was not prepared to provide such funding until enactment of the Energy Act 2016 because of uncertainty about whether it would be enacted / how it would be worded if enacted; and

(iii) the wind farm / additional capacity would have been commissioned / added on or before 31 March 2017 if the funding had been provided before enactment of that Act; and

(b) a letter or other document dated on or before 1 May 2016 from a recognised lender confirming that it was not prepared to provide funding for the wind farm / additional capacity until enactment of the Energy Act 2016.

32LI Between 1 January 2018 and 31 December 2018 Approved development condition

and

Investment freezing condition

and

Grid and radar delay condition – noting that:

Documentary requirements are as described in relation to section 32LE, but

For the purposes of section 32LI, the primary date is 31 December 2017.

It seems likely that the Government’s proposed amendments will be adopted. It remains to be seen whether subsequent debates as the Energy Bill passes through the remaining stages of its passage through the House of Lords, or through the House of Commons, will result in the addition of any further grace period criteria or the tweaking of those already covered. For now, the following points may be noted:

  • The grace period criteria based around a combination of planning, grid and land rights proposed in July have been broadened as regards planning permission.  In particular, what is now called the “approved development condition” allows grace period status to be claimed not just by projects that had obtained planning permission by 18 June 2015, but also by those who had their planning applications refused on or before that date, but have managed to obtain planning permission through an appeal or judicial review process subsequently.  The value of a further extension, relating to cases which local authorities have failed to handle according to statutory timetables, may be more limited, because as currently drafted it appears only to benefit cases that have not been referred to Ministers for determination.
  • The introduction of provisions acknowledging that some projects may be delayed because lenders are unwilling to commit to finance them before the legislation has received Royal Assent is clearly a welcome addition to the package of mitigation for early closure.  However, note that the “investment freezing condition” in which this is set out does not function as an independent justification for not commissioning by 31 March 2016.  Rather, it allows those projects that can already justify an extension of the period within which they can achieve accreditation under the approved development condition to extend for an additional 9 months.
  • In July 2015 DECC had already indicated that projects which benefited from planning, grid and land rights on 18 June 2015 could bring themselves within the scope of the existing grace period provisions on grid and radar delay – thereby potentially enabling them to apply for accreditation as late as 31 March 2018 where such delay had occurred.  The proposed amendments to the Energy Bill disapply the grace period provisions of the Renewables Obligation Closure Order 2014 from onshore wind projects, but reproduce the effect of its provisions on grid and radar delay as part of their own suite of grace period criteria.
  • The revised impact assessment produced alongside the proposed amendments does not appear to suggest that any more capacity will be accredited as a result of the expansion of the grace period criteria (the numbers in all the key tables are the same as in the version of the impact assessment published in September, apparently on the basis of the original proposals).  However, the accompanying DECC press release states that “around 2.9 GW” of onshore wind capacity could be eligible for the grace periods.

The package of mitigation proposed by the amendments is appreciably more generous than what was suggested by DECC in July, but there are limits to that generosity.  For example, the amendments have not simply followed the model established by the >5MW solar PV RO grace period and allowed the planning criterion within the approved development criterion to be satisfied by any project that had applied for planning permission by 18 July 2015.  However, it is noticeable that the DECC policy paper of 8 October 2015 invites “onshore wind developers to tell us about any of their projects affected by our proposals. In particular, we are interested in hearing from developers with projects that are currently in the planning system, but which have not yet secured planning consent, and to receive information and evidence relating to:

  • the stage that such projects have reached in the planning process, anticipated final planning decision dates, and expenditure incurred on projects as at the date of the Secretary of State’s announcement
  • project timetables and anticipated dates for securing a grid connection offer and acceptance; and
  • the prospects of such projects being in a position to accredit under the RO by 31 March 2017 and expected final investment decision dates.”

It is therefore possible that Government is leaving the door open (or, at least, slightly ajar) to a revised ‘approved development condition’ that more closely resembles the model established by the >5MW solar PV RO grace period (and is more favourable to the industry than that currently tabled in the Energy Bill).

Conversely, it will be interesting to see whether some of the new concepts introduced by the proposed ‘grace period’ conditions for onshore wind, such as the investment freezing condition, will find any place in DECC’s eagerly awaited response to its consultation on the proposed early closure of the RO to ≤5MW solar PV projects.

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Grace periods for early closure of Renewables Obligation support for onshore wind

DECC’s latest consultation on Feed-in Tariffs – an Era of “FIT Austerity”?

The UK Department of Energy and Climate Change (DECC) has launched a consultation proposing savage cuts in the levels of subsidy under the Feed-in Tariffs (FITs) regime for small-scale renewable electricity generation (the Consultation).  This comes only a few weeks after DECC announced the ending of more or less all subsidies for onshore wind, the removal of the renewables exemption from the Climate Change Levy and other proposals designed to reduce the costs of renewable subsidies significantly.  What does the Consultation say, and what does it mean for the future of renewables in the UK?  We look first at the background of the FITs regime and then at the detail of the proposals.

Some background

The legal foundation for the FITs regime was inserted very late in the Parliamentary passage of the Bill that became the Energy Act 2008.  Although there had been pressure to include provision for FITs from the moment the Bill was introduced in January 2008, the then Labour Government only finally gave in to it on 5 November 2008, by which time the Bill was rubbing shoulders in the Parliamentary timetable with legislation designed to avert financial meltdown as a result of the banking crisis.

Perhaps we should not be surprised that a scheme launched in the far-off days of Gordon Brown’s premiership should now be in the process of being dismantled, after 5 years of apparently too successful operation, as part of the current Conservative Government’s attempts to reduce public spending (whether funded from taxation or levies on consumers).  To see quite how different the world looked in 2008, it is worth recalling that Ministers then looked forward to a time when, by 2020, the Renewables Obligation (RO), newly modified to include different bands of support for different technologies would be “worth about £1 billion a year in support of the renewables industry”.  Current annual support under the RO runs at around three times this level, and it may hit £5 billion by 2020.

During the passage of the 2008 Energy Bill, EU Member States were set the targets for the percentage of final energy consumption from renewable sources that they would have to meet by 2020 under the Renewables Directive of 2009.  Some suggested that the UK would not meet its target of 15% unless FITs were introduced.  There was a widely held view that following the German model of FITs was at least an essential supplement to the RO, and that feed-in tariffs were generally, and could be in the UK, a cheaper way of subsidising renewables.

That was perhaps over-optimistic.  DECC and Ofgem figures show that in 2013-2014, generating stations accredited under the RO produced 49.6 TWh, or 16.3% of electricity supplied in the UK. At the same time, FIT installations produced 2.6 TWh, or 0.84% of the UK’s final consumption of electricity.  But whilst the output of RO-subsidised generation to FIT-subsidised generation stood in a ratio of about 19:1, the comparative costs of RO were no more than 4 times those of FITs.  Another comparison from DECC’s evidence review of FITs is even more interesting, when it calculates that the p/kWh cost of FIT-generated electricity is about 3 times the level of the strike price under the proposed Contract for Difference (CfD) for the Hinkley Point C nuclear power station.

Perhaps this should come as no surprise.  FITs were intended as a way of encouraging “microgeneration”.  One of the ways that renewables resemble other forms of power generation is that they tend to be more cost-effective on a larger than on a smaller scale.  But FITs were not just about meeting targets: they were to make renewable generation accessible to individual households for whom trying to deal with the RO was (in the words of one MP, apparently speaking from personal experience) a “bloody nightmare”.  FITs would be simple, and they would popularise renewables.

That part certainly seems to have worked.  As DECC notes, the scheme has all but reached 750,000 FIT installations already – a level it was not originally expected to reach until 2020.

Headline proposals

DECC says that the deployment of FITs has been significantly exceeding its projections both in terms of numbers of installations and installed capacity. As a result, the FIT scheme has put undue financial pressure on the Levy Control Framework (LCF), which was created to limit the extent to which consumer bills increase to fund the subsidies for low-carbon generation.  The measures proposed in the Consultation are intended to remedy these problems.

Significant decreases in generation tariffs for solar PV, wind and hydro power 

At the larger end of the scale of FIT eligible installations, generation tariff reductions are proposed for:

  • standalone solar PV (Large Solar PV) – from 4.28 p/kWh to 1.03 p/kWh;
  • wind farms with a capacity >1.5 MW (Large Wind) – from 2.49 p/kWh to 0 p/kWh; and
  • hydro installations with a capacity  >2MW (Large Hydro) – from 2.43 p/kWh to 2.18 p/kWh.

Installations with smaller capacity would also see their tariffs reduced, in the case of solar PV, even more steeply, with 4 kW installations having an 87% reduction in generation tariff levels.

In addition, the different capacity-based generation tariff bands for each technology would change (their number being reduced in the case of wind and hydro and the boundaries redrawn for solar).

It can be said that the relative levels of reduction in generation tariffs roughly correspond to the extent to which DECC’s Impact Assessment reckons the different sizes and types of installation have seen reductions in their grid connection and capex costs since 2012.  But only roughly: for example, it appears that Large Solar PV has seen an increase of 3% in costs and will have its tariff reduced by 76%, while the smallest PV installations have seen a decrease in costs of 35% and will have their tariff reduced by 87%. These reductions in generation tariffs are said to be aiming at a target rate of return of 4%, as compared to the 5-8% range of rates of return that was used to calculate the current tariff rates

The changes would mean that for future solar PV installations, the generation tariff (received on all the power they generate) would be a much less significant component of their revenue stream than it has been historically.  For those receiving the export tariff for the electricity which they export (or are deemed to export), the export tariff is likely, at least initially, to be higher in p/kWh terms, but by far the largest benefit for those who consume the renewable electricity that they produce will be in the avoidance of the costs of purchasing electricity generated elsewhere from a third party supplier.

The problem for most solar installations though, especially on domestic premises, is that for much of the year, the bulk of household energy consumption tends to occur at times when there is no sun and no generation.  The solution to that would be to connect your PV panels to a battery and store the electricity generated during daylight hours for the evening.  But – needless to say – the Consultation contains no proposals for any new German-style subsidy for adopting storage technology.

Degression

At present, FIT generation tariffs “degress” periodically by a fixed percentage automatically, but can degress further if deployment reaches specified thresholds (contingent degression).

The Consultation proposes:

  • a new fixed quarterly degression mechanism, reducing generation tariffs available for new Large Solar PV to zero by January 2019.  DECC is not proposing to degress the generation tariffs for Large Hydro, which would stand at 2.18p/kWh throughout the three-year period budgeted for under the Consultation;
  • harmonising the frequency of degression to quarterly across all technologies; and
  • a further degression of 5% if deployment of FITs exceeds DECC’s deployment projections, and 10% if the cap (discussed below) on the eligibility of new projects for the FIT scheme is reached.

The Impact Assessment takes as a working assumption the proposition on which DECC consulted in July, that future FIT eligible installations will not be able to protect themselves from the impact of degression by applying for preliminary accreditation when they have planning permission and an accepted offer of a grid connection, thereby “locking in” to the higher tariff band prevailing at the time of preliminary accreditation for a period of between 6 and 30 months (depending on technology and ownership of the installation) provided that they are commissioned and accredited within that period.

Indexation

Previously, both generation and export tariffs have risen automatically in line with the Retail Price Index (as under the RO).  New installations will see their tariff payments rise according to the movements of the Consumer Price Index link (as under the CfD regime), which is less generous.

Overall cap

So far, the proposed changes, although they slash the amounts of support available to new installations, leave the basic architecture of the regime in place.  But the existence of the proposed new FIT regime is a much more precarious thing than might be suggested by any of the above.

This is because DECC further proposes:

  • a maximum overall budget for the FIT scheme of £75 – 100 million for the period from January 2016 to 2018/2019.  This would apparently be expressed as a series of quarterly limits on FIT-supported deployment at each generation tariff level, so that once the cap is reached no further generating capacity would be eligible for the tariff during the period to which the cap applies;
  • separate caps for each of a number of different capacity-based bands for solar and wind (each of which cover a number of generation tariff bands).  These would limit quarterly FIT solar deployment, for example, to between 42 MW and 54 MW during the period budgeted for by DECC in the Consultation (Q1 2016 – Q1 2019).  This is less than is typically accredited in a single month at present.  The caps on larger solar installations would limit deployment under FIT to one or two per quarter; and
  • unlike the measures relating to generation tariffs and degression, the caps would apply to anaerobic digestion (AD) installations as well as solar, wind and hydro.

With exquisite understatement, DECC observes: “We recognise that implementing deployment caps presents significant logistical challenges.”, although DECC has outlined a number of possible ways in which the caps might be administered (essentially, by Ofgem or by licensed suppliers).  Anticipating the possible objections to a system where eligibility for a particular tariff (or any support at all) would depend on the relative timing of accreditation of different installations, measured in seconds, DECC proposes to suspend the FIT regime pending any better suggestions.  Anticipating the objection that a cap will simply not achieve its purpose of controlling costs, the Consultation proposes the alternative solution of ending generation tariffs altogether, possibly as soon as January 2016.  The industry is, in effect, challenged to accept the capping proposals or face potentially worse consequences.

Almost as an afterthought, DECC adds that its consideration of “further amendments to the existing FITs scheme to ensure that it provides better value for money” includes “consideration of whether future applications within a system of caps could be prioritised through a competitive process“.  It’s a pity the CfD regime, with its competitive allocation process, wasn’t designed to cover microgeneration.

Other points

DECC is concerned that (especially in the wind and AD sectors) the “extension” of an existing FIT installation – or developing what is in truth a single installation in a series of separately accredited stages – can be used as a way to gain the benefits of economies of scale associated with larger installations whilst qualifying for the higher generation tariff rates associated with smaller installations, leading to “overcompensation”.  To put an end to this, it is proposed to “put in place a rule to prevent new extensions claiming support under FITs.”  No detail is given as to how this will work in practice.

When the Energy Bill was being debated back in 2008, three issues were often raised (not necessarily in connection with FITs) on which less progress has been made in the intervening years than could have been wished: smart meters, the impact of small-scale renewable generation on distribution networks, and energy efficiency.  The Consultation has something to say on each.

  • DECC propose to end the practice of estimating how much electricity smaller installations export to the grid (deemed exports) in favour of full metering of exports, and may take further measures to enable remote generation meter reading.  The key question here seems to be whether existing installations of 30kW and below should be compelled to accept smart or “advanced” meters in order to facilitate this more accurate and “remote” measurement of their FIT entitlements.  DECC note that deemed exports were meant to be a temporary measure.  It remains to be seen whether smart meters will be rolled out before the FITs regime closes to new installations.
  • More accurate measurement of exports would facilitate a further reform: moving to “dynamic” export tariff rates that could reflect changes in the wholesale price of electricity, rather than the current, static export tariff rates.  It is a matter of concern to DECC that “the current export tariff is higher than the wholesale electricity price, with resulting overcompensation of generators by suppliers“.  This is because the tariff is meant to represent the wholesale price less the value of the transmission and distribution costs which suppliers do not have to pay in respect of FIT electricity (even though, DECC acknowledges slightly confusingly “in certain circumstances these can be additional rather than avoided costs“).
  • DECC propose an obligation to notify DNOs of new small-scale generators to facilitate grid management.  The problems of DNOs not being made aware of new generation on the grid are not new.  Such an obligation is perhaps a case of “better late than never”, but would no doubt have been more welcome to DNOs when FIT generating capacity was still increasing at a rate unconstrained by the proposed new caps.
  • DECC propose that roof-mounted solar PV installations seeking to accredit at the higher generation tariff rate should satisfy the requirement of being at least in energy efficiency band D before they commission the solar installation, rather than being able to count the installation itself as one of the things entitling them to be certified at band D or above.  Under the current regime, the higher tariff sees to have become effectively a default rate, applying to 99% of installations, rather than setting any kind of incentive to improve the energy efficiency of buildings.  DECC mentions, but is not yet proposing, the further step of raising the higher tariff threshold to band C.

Finally, DECC is “considering implementing”, but is not yet proposing, changes such that AD plants that sought accreditation under the FIT regime would have to comply with the same sustainability requirements that the feedstock of AD plants seeking support under other renewable incentive mechanisms (e.g. the RO and Renewable Heat Incentive) are required to observe.  This would be to avoid FITs becoming a haven for operators with non-compliant feedstocks.

The good news?

In contrast to some of its recent proposals in relation to the RO, DECC has reasserted its commitment to its “grandfathering” policy on FITs, so that existing installations will not be affected by the proposed changes to tariffs and caps.  However, the Consultation does not address explicitly the question whether any tariff reductions will affect projects which have been pre-accredited (whilst this was still possible) but have not achieved full accreditation at the point when the new tariffs come into effect. Such projects are likely to be at risk of being subject to the new, lower tariffs if construction or grid connection delays result in them not being commissioned and applying for full accreditation within their pre-accreditation periods of e.g. 6 months (12 months for community projects) for solar PV.  But it is to be hoped that if they are commissioned and accredited within their pre-accreditation periods, they will still benefit from the earlier, higher tariffs prevailing at the time of their pre-accreditation.

What next?

The proposed measures in the Consultation, if implemented, will bring about a drastic change in the FITs regime.  Is this anything more than the latest manifestation of fiscal austerity, or are the Government’s proposals for the FITs regime part of a coherent renewables / energy policy?

There are a number of points on which the proposals are notably consistent with other statements of the present Government’s policy on renewables.  The gentlest decrease in solar PV generation tariffs (a mere 62%) has been applied to the 250-1000kW band which most obviously represents the commercial rooftop solar sector that DECC has said it wants to see expanding.  The fact that wind generation tariffs have only been abolished for installations above 1.5kW (with proposed tariff reductions of as little as 37% for the smallest wind installations) tends to reinforce the impression that the current Government’s objections to further onshore wind subsidies owe as much to aesthetic as to financial considerations.  There is a general intention that tariffs should be set at a level that encourages “well-sited” installations rather than making viable those that ought not to be viable.

As noted above, the UK nearly didn’t have a FIT regime.  Political pressure ensured that it did.  It may be that calculations of what was and was not politically feasible resulted in the regime being unreformed for too long after its 2012 review.  A number of the ideas in the Consultation feel as if they could have been more usefully deployed if they had been proposed much earlier, but may now come too late, and/or in too Draconian a form, to save the regime as far as any significant quantity of new installations is concerned.

Whether, in retrospect, the proposals will look like a well marked out path to subsidy-free small-scale renewable generation is hard to assess.  However, it is clear that DECC is determined to avoid a situation in which a large bulge of smaller projects that fail to make the relevant cut-off date for accreditation under the RO flood into the FIT regime instead.  The proposed caps should stop that.

If you would like to discuss any issues arising from this post, please feel free to contact the authors or another member of the London Energy team at Dentons.

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DECC’s latest consultation on Feed-in Tariffs – an Era of “FIT Austerity”?

Large scale solar and the Renewables Obligation: 9 more months of grace

DECC has confirmed that there will be a further year-long grace period for large scale solar PV projects which fail to be accredited under the Renewables Obligation (RO) by 31 March 2015.  In addition to the previously announced grace period for projects which are considered to have made a “significant financial commitment” before 13 May 2014, there will be a further opportunity for those projects which only fail to be accredited by 31 March 2015 for lack of a grid connection.

DECC’s announcement came in a response to a consultation that ran from 2 to 24 October 2014 and followed on the 13 May 2014 consultation on early closure of the RO to large scale solar PV (see our earlier post).   The key difference from what was proposed in the 2 October consultation document in relation to the proposed grid connection grace period is that it will now run for a full year, like the grace period for “significant financial commitment” projects, rather than just three months – giving those projects that meet the relevant criteria until 31 March 2016 to achieve accreditation.

Alongside the response to consultation, DECC has published a draft of the statutory instrument that it proposes to lay before Parliament in the New Year to amend the existing RO Closure Order.  This makes it possible to see exactly how DECC envisages eligibility for both grace periods working. 

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Large scale solar and the Renewables Obligation: 9 more months of grace

Early closure of RO to >5MW solar PV projects confirmed

Following a consultation that ran from 13 May to 7 July 2014, the UK Government has confirmed its intention that, as a general rule, funding under the Renewables Obligation will not be available to larger scale (>5MW solar) PV projects after 31 March 2015.

There will be a “grace period” of a year for projects which were, in effect, in a position to begin development before 13 May 2014.  Perhaps more usefully for projects which may struggle to meet the requirements for RO accreditation before 31 March 2015, further consultation is taking place on a proposal to protect the position of those projects which only fail to meet the 31 March 2015 cut-off date for commissioning because their electricity network operator has not met a pre-31 March 2015 estimated connection date.

Background

For most technologies, the Renewables Obligation will close on 31 March 2017.  After that date, smaller projects will have to rely on the Feed-in Tariffs regime and larger projects must compete for Contracts for Difference (CfDs) under Electricity Market Reform.  In March 2014, the Government set out its overall approach to the two and a half year  transition period when both the RO and CfD regimes are open to new projects: developers are able to choose between the two schemes (subject to certain qualifications). But subsequently DECC has become increasingly concerned that the rapid growth of the UK solar industry, supported by the “demand-led” RO, will breach the Levy Control Framework (LCF) limits on the overall amount of money that the Treasury will permit to be spent on renewable energy subsidies.  In its May 2014 consultation, DECC estimated that large-scale solar PV deployment under the RO could reach “more than 5GW by 2017”; in the response to that consultation, DECC’s “updated assessment” found that “in the absence of intervention”, up to 10GW of solar PV could deploy within this period, costing some £400m more than was allowed for in the EMR Delivery Plan and exceeding the LCF cap.

Proposals and policy decisions

The table below summarises the Government’s main proposals on RO closure for solar PV in the May consultation and the policy decisions announced in the response to consultation.

table-1

DECC has not been persuaded to change the cut-off date or open up the grace period to a wider group of projects.  Responding to “the main criticism…that any projects that can meet the grace period…requirements are unlikely to need the grace period because they will already be sufficiently advanced to secure connection by 31 March 2015”, DECC states that “the grace period will have fulfilled its purpose if it protects eligible projects that subsequently encounter unexpected events which delay their completion beyond the end of March 2015.  However, DECC very clearly has taken on board the industry’s practical objections around the evidence to be provided by those that are eligible for the grace period and has accommodated its evidential requirements to the realities of the industry.

Further consultation

In response to comments from consultees that early closure of the RO to large-scale solar would create a “cliff-edge” effect for some projects, DECC has put out a further consultation (closing on 24 October 2014) on the proposal that there should be a separate 3 month grace period (until 30 June 2015) for projects which are prevented from meeting the 31 March 2015 deadline only because they are not connected to the grid by that date.

The proposal is that such projects would have to include in their RO application:

  • a grid connection offer and acceptance and a letter from the network operator estimating or setting a date for connection of no later to 31 March 2015 (the estimated connection date);
  • a declaration by the developer that to the best of its knowledge, the project would have been commissioned by 31 March 2015 if the connection had been made by the estimated connection date; and
  • a letter from the network operator confirming that in its opinion, the failure to make the grid connection before the estimated connection date was not due to any failure on the part of the developer.

The first of these proposed requirements is open to the same sorts of objections that were made by the industry against the proposed requirement for a letter from the network operator that formed part of the May 2014 proposals.  However, DECC insists that past experience on banding review grace periods suggests that the difficulties associated with it are “not insurmountable”, and the response to consultation is careful to note that the requirement has been removed from the final policy decision on the May proposals because a letter from the network operator was considered unnecessary in that context, rather than that it would be too difficult to obtain.

What next?

DECC intends to implement the policy decisions described above in relation to RO closure through an amendment to the Renewables Obligation Closure Order 2014, to take effect on 1 April 2015.

DECC is evidently determined to do whatever it has to in order to mitigate the risk that the growth in large-scale solar PV will lead to a breach in the Levy Control Framework limits. It wants the sector to switch to the CfD regime, where the auction-based allocation process will drive down the costs of subsidy, acknowledging that the greater complexity of the CfD regime will favour the larger players in the industry.

The deadline for applications for the first CfD round is now 30 October 2014, and in recent publications both DECC and National Grid (as EMR Delivery Body) have been doing their best to make the regime user-friendly.  The table below suggests which groups of developers may need to consider making a CfD application.  If onshore wind developers (with whom solar projects must compete) are likely to avoid bidding for CfDs in the first auction since they  have until 31 March 2017 to achieve RO accreditation, it may be that solar projects stand a reasonable chance of success of being allocated CfDs later this year.

table-2

At present, for those who miss out on both the RO and a CfD from the first allocation round, the next opportunity would be a CfD allocation round in Autumn 2015.  DECC has given some indications that it is sympathetic to the proposition that the rapid development cycle of solar projects means that there ought to be solar CfD allocations every 6 months rather than every year, as for other technologies, but it also points out that more frequent auctions would not mean any increase in the overall budget.  And since 2015 is a General Election year, no promises of a further allocation round for solar can be made at present.

 

 

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Early closure of RO to >5MW solar PV projects confirmed