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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

Global perspectives on the energy sector

What is the future for traditional power utilities?  What can Europe learn from the US experience of capacity markets?  What is holding back the development of the power sector in Africa?  What are the key political and economic considerations for those investing in Middle East energy projects?  How should energy companies deal with cyber security risks?  How can they gain business advantage by engaging proactively with Human Rights law and international investment treaties?  Where is the oil price going and what does that mean for industry consolidation?  Will the Paris 2015 UN Climate Change talks succeed where others are perceived to have failed?  How can projects to prevent deforestation be made to pay their way?

For perspectives on these and other hot topics in the energy sector worldwide, see our Global Energy Summit London 2015: Key Themes report, based on presentations given on 21 and 22 April 2015 in Dentons’ London Office by a range of expert contributors.  Individual presenters’ slides are also available on our website.

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Global perspectives on the energy sector

Failure of competition in retail energy markets: “disengaged customers” (still) the root cause?

Emerging analysis from the investigation into GB gas and electricity supply by the UK’s Competition and Markets Authority (CMA) suggests that consumers are paying more than they need to because of their failure to “engage in” the market and because of shortcomings in the regulation of the sector.

Some seven months into an investigation instigated by Ofgem and six months after producing its initial issues statement setting out the areas on which it would be focusing, the CMA has published an updated version of the issues statement and a summary of smaller suppliers’ views on barriers to entry and expansion in the market (one of a series of “working papers” that provide more detail of the CMA’s analysis and the evidence on which it is based).

The problem

The CMA is fairly clear that both domestic and “microbusiness” consumers of gas and electricity are paying more than they need to – noting, for example, that “95% of the dual fuel customers” of the Big 6 could have saved an average of between £158 and £234 by switching tariff and/or supplier.  They also note, as others have done before them, that customers on “Standard Variable Tariffs” (SVT) tend to see their bills rising faster and falling slower than increases and decreases in the underlying costs of supply would suggest (the so-called “rocket and feather” effect – see graph below).

CMA fig 1

The search for causes

However, the CMA has so far rejected a number of the “usual suspects” when it comes to explaining why consumers appear to be paying more than they need to, without there being any obvious reason for their loyalty to their existing suppliers.  The initial issues statement was based on four hypothetical “theories of harm” that could account for failures of competition:

  • “market power in electricity generation leads to higher prices;
  • opaque prices and/or low levels of liquidity in wholesale electricity markets create barriers to entry in retail and generation, perverse incentives for generators and/or other inefficiencies in market functioning;
  • vertically integrated electricity companies harm the competitive position of non-integrated firms to the detriment of the customer, either by increasing the costs of non-integrated energy suppliers or reducing the sales of non-integrated generating companies;
  • energy suppliers face weak incentives to compete on price and non-price factors in retail markets, due in particular to inactive customers, supplier behaviour and/or regulatory interventions.”.

Taking each of these in turn, the CMA’s current (but explicitly provisional) analysis is as follows:

  • The Big 6 are not making excessive profits from generation and do not have the ability or incentive – individually or collectively – to increase profits by withdrawing capacity.
  • There are not significant problems as regards the transparency of the wholesale markets.  Those smaller suppliers who complain about a lack of liquidity, at least for certain products, have yet to persuade the CMA that this is a major concern, although they note that Ofgem’s Secure and Promote licence condition has not addressed all the problems in this area.
  • The CMA also does not think that the Big 6’s vertical integration enables them to cause independent generators to restrict their output or allows them to take action in the wholesale markets that disadvantages independent retailers.  One independent supplier saw vertical integration as a competitive disadvantage (potentially tying a supplier to generating plant whose efficiency reduces over time, especially if measured against the best in the market).
  • The only one of the original “theories of harm” which seems to offer an explanation of the failure of competition is the fourth one above, notably “inactive consumers”.  Although the domestic market share of independent suppliers grew from 1% to 7% (electricity) or 8% (gas) between July 2011 and July 2014, the fact remains that almost half of domestic consumers have not switched supplier for at least 10 years.  Many do not even believe switching is possible.  As one of the independent suppliers points out, having a large base of relatively price-insensitive customers on SVT may enable an incumbent to compete more aggressively against new entrants for the business of those who do take active steps to get a good deal.  Another suggests that it is almost as if there are two markets: one composed of potential switchers and another of those who are terminally loyal to their incumbent supplier.

Regulation may be stifling competition

One of the things that stands out in the CMA’s analysis is the emphasis on the potentially adverse effects that various aspects of sectoral regulation may be having on competition.  This is most conspicuous in the addition of two new hypothetical “theories or harm”:

  • “the market rules and regulatory framework distort competition and lead to inefficiencies in wholesale electricity markets;
  • the broader regulatory framework, including the current system of code governance, acts as a barrier to pro-competitive innovation and change.”.

But it is also seen elsewhere.  Examples of potentially problematic regulation identified include:

  • Elements in Ofgem’s recent reform of cashout prices (the Electricity Balancing Significant Code Review) “may lead to an overcompensation of generators”.
  • It may be inefficient not to have a system of locational prices for constraints and losses on the transmission network.  It may be that consumers in Scotland and the North of England should be paying more, and those in the South of England paying less, for their electricity.
  • The Capacity Market element of Electricity Market Reform (EMR) “appears broadly competitive”, but the CMA plan to look at if further.  They note that the Contracts for Difference regime may not secure the lowest prices for renewable generation subsidies by having separate “pots” for different technologies, rather than requiring them to compete all-against-all, or by allowing the award of contracts on a non-competitive basis, before observing, equally obviously, that “there are potentially competing objectives that need to be taken into account in the design of the CfD allocation mechanism”.  One independent supplier also characterises the system by which CfD costs are recovered from suppliers as “madness”.
  • But any problems caused by EMR are for the future.  Looking back, the CMA have clearly listened both to those who have criticised Ofgem’s 2009 decision to prohibit regional price discrimination (while providing exemptions for promotional tariffs), which may have led to a consumer-confusing increase in the number of tariffs, and to those who question Ofgem’s 2013 decision to force suppliers to “simplify” their tariff portfolios drastically, which resulted in the loss of tariff discount options that may or may not have been valued by consumers.  However, the CMA have yet to form a final view on the merits of either decision.
  • It has often been observed that the 250,000 account threshold, above which suppliers become subject to the Energy Company Obligation (ECO), may act as a barrier to growth for independent suppliers.  More interestingly, the CMA note that the costs of the social and environmental policies delivered by suppliers “fall disproportionately on electricity rather than gas”, meaning that “domestic consumption of electricity attracts a much higher implicit carbon price than domestic consumption of gas” – which may have implications for the take-up of electrical heating systems (normally thought of as part of decarbonising energy usage).  This is another area where the CMA will be investigating further.
  • Finally, the CMA identify aspects of the Balancing and Settlement Code (BSC) and other industry agreements that could be standing in the way of more effective competition.  They ask, for example, why, once smart meters have been rolled out, there are no plans to move away from the system whereby domestic customers’ consumption is “profiled”, rather than being based on half-hourly meter readings.  Failure to take advantage of the new technology in this way could “distort incentives to innovate”.  The CMA will also be considering further whether there are just too many codes in the electricity industry (constituting a barrier to entry) and whether the mechanisms for changing industry rules may be stacked too heavily in favour of incumbents and the status quo.  On the first point, Elexon itself, administrator of the BSC, apparently thinks that “rationalising” the codes will remove potential barriers to competition.

Next steps

Interested parties have until 18 March 2015 to comment on the updated issues statement.  The next major step will be the publication of “provisional findings”, currently scheduled for May 2015.  Overall, the investigation is not due to conclude before November / December 2015, and it could be extended into 2016.  It is of course far too early to speculate on possible remedies, but for now the more obviously Draconian options in the CMA’s armoury, such as the breaking up of vertically integrated groups, appear unlikely outcomes.  Something eye-catching to cause “inactive” consumers to “engage”, and a lot of “boring but important” changes in the regulatory undergrowth around industry codes and agreements seem reasonable bets for now, but there is a long way to go yet.

 

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Failure of competition in retail energy markets: “disengaged customers” (still) the root cause?

Clearing the way for UK shale (and deep geothermal) exploitation: Infrastructure Bill Update (2)

In the previous post we looked at the new right to exploit deep-level land for petroleum extraction and deep geothermal projects that is now included in the Infrastructure Bill.  Here we report on the associated financial provisions and some proposals on shale-related matters that have so far not found their way into this part of the Infrastructure Bill.

The Infrastructure Bill provides for secondary legislation about “payment schemes”.  The Government favours the voluntary scheme proposed by industry, under which a one-off payment of £20,000 would be made to communities for each unique horizontal well that extends by more than 200 metres laterally.  So although Ministers will be able to make regulations requiring payments to owners of land over which the new right is exercised (and other persons for the benefit of areas in which such land is situated), the Government currently intends to use these powers only if the voluntary scheme “is not honoured”.

Regulations may also require notice to be given where the new statutory right to use deep-level land for petroleum extraction or deep geothermal projects is to be exercised, including notice of any applicable statutory payment scheme.  The secondary legislation powers are to be reviewed after five years and must be repealed after seven years if they have not been used and the Secretary of State is satisfied that they are no longer required.

The principle behind the clauses on the new right was not seriously opposed in the House of Lords debate.  Amendments were put forward proposing to exclude National Parks and other areas protected for nature conservation or heritage reasons from exercise of the new right, and to require DECC to publish a report on fugitive green-house gas emissions from onshore energy extraction.  Like most of the responses to the Government’s consultation on the new right, these were treated as merely general warnings about potential impacts of shale development that the existing regulatory frameworks are fully capable of addressing.  However, it is always possible that they may re-surface at a later stage in the passage of the Infrastructure Bill, when they can be voted on (by convention there are no votes at the Lords Grand Committee stage which has just concluded).

A separate shale-related amendment was proposed by the Conservative Peer Lord Hodgson of Astley Abbotts.  Drawing on the example of Norway (like the Scottish National Party in the run-up to the Independence Referendum), Lord Hodgson advocated the establishment of a shale sovereign wealth fund.  This would receive “no less than 50% of any revenue received by the United Kingdom Government from any activity connected with the extraction and sale of shale gas”, and its assets would be “deployed to serve long term public objectives other than those connected with monetary and exchange rate policy”.  Lord Hodgson argued that it is imprudent and – from an inter-generational perspective – unfair for all tax revenues from major natural resources such as UK shale gas to be spent when they are received.  So far, the Government response to is that the industry is too immature and the Treasury might need to spend 100% of the revenues from shale gas when it receives them, especially in view of the declining North Sea revenues.

For more shale-related posts, including commentary on the 14th Onshore Licensing Round, see Dentons’ UK Planning Law Blog.

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Clearing the way for UK shale (and deep geothermal) exploitation: Infrastructure Bill Update (2)

Shared Ownership – Shared Responsibility

The Community Energy Strategy (Strategy) published by the Department of Energy and Climate Change (DECC) set the expectation that “by 2015 it will be the norm for communities to be offered some level of ownership of new, commercially developed onshore renewable projects”. As a step towards achieving this aim, DECC requested the establishment of the “Shared Ownership Taskforce” formed of representatives from the renewables industry (Industry Taskforce). The Industry Taskforce’s mandate was to liaise with communities and, by September 2014, produce a robust framework and timetable for the implementation of widespread community ownership of renewables projects.

Whilst engagement with the Strategy is nominally voluntary, DECC made it clear that if by 2015 progress towards its community ownership objectives is unsatisfactory, it will consider requiring, by law, all developers to offer shared ownership to communities. This imperative was given further teeth in the draft Infrastructure Bill published on 6 June 2014 (Draft Bill). The Draft Bill sets out a broad enabling power (to be activated, or not, at DECC’s option) to give community residents and/or community groups the right to invest in renewable electricity generation projects located within their community.

Draft Report for Consultation

In this policy context, the Industry Taskforce published its Draft Report for Consultation on 23 June 2014 (Draft Report). The Draft Report sets out the Industry Taskforce’s initial proposals for shared ownership and invites further views from renewable industry stakeholders, before publication of its final report in September 2014.

The Industry Taskforce’s key recommendation was that commercial developers seeking to develop significant renewable energy projects (above £2.5 million in project costs) for the primary purpose of exporting energy onto a public network should offer local people the chance to invest alongside the developer. Such an offer should be a based on a fair market value and should be subject to an (as yet unspecified) minimum threshold for investment (as very small levels of community ownership may be commercially unviable).

The Industry Taskforce recommended that communities should be able to choose between three different ownership models:

  1. Split ownership: the project is divided into two or more separate generating systems, allowing for the community entity and the developer to own distinct generating assets.
  2. Shared revenue: although not strictly an “ownership” model, this model enables the community entity to buy rights to the project’s future revenue streams.
  3. Joint venture: the community entity and the developer jointly develop and own the project.

Government’s role

The Draft Report was clear that Government has a key role to play to ensure that shared ownership is a success. For example, financial support mechanisms and planning were identified as two areas in which Government support was critical.

Financial support mechanisms

The Draft Report notes how financial support mechanisms for renewable energy are currently in a state of flux. Examples of such flux include DECC’s consultation to increase the capacity ceiling for community projects eligible for the Feed-in Tariff from 5MW to 10MW, the replacement of the Renewables Obligation with Contracts for Difference by 2017, and the potentially insufficient budget set aside to fund the Levy Control Framework. Furthermore, it is also unclear whether DECC intends to create a bespoke support mechanism for shared ownership schemes, or rely on existing support mechanisms.

In response to this policy uncertainty, the Draft Report argues that the Government must provide greater clarity in relation to the types and levels of financial support available to both the community and commercial developers in order to encourage the uptake of community ownership.

Planning

The Draft Report argues that shared ownership is currently not given enough weight when planning decisions are taken. In addition, the complex and expensive planning process (often requiring detailed environmental impact assessments) can act as a barrier to entry for certain communities.

To address this issue, the Industry Taskforce recommends that shared ownership should become a “material planning consideration” in the determination of renewable planning applications and that local authorities should treat discussions regarding community ownership in a similar way to discussions with residential applicants (i.e. through enhanced planning officer support). Such a supportive approach would be consistent with the Government’s shared ownership ambitions.

Conclusion

A clear message from the Draft Report is that UK renewables industry representatives are willing to engage on the issue of shared ownership. Indeed many shared ownership projects already exist and are successful. However, the renewables industry suggests that it should not bear the burden alone. For shared ownership to succeed, it is argued that the Government must offer tailored practical and financial support (as it is noted to have done indirectly with the UK’s nascent shale industry, whereby local authorities will be entitled to retain 100% of the business rates collected from shale sites).

Dentons was delighted to host a Joint Renewable Energy Association/Solar Trade Association Members’ Meeting on 23 June 2014 at which the Draft Report was presented and discussed. A copy of the Draft Report and Taskforce working papers are available on the RenewableUK website.

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Shared Ownership – Shared Responsibility

Themes from Budget 2014 (2): investment in renewables projects – a boost for communities?

Budget 2014 limits the scope for obtaining tax relief on investments in renewables projects, but it also opens up a new relief, of which some renewables investors may be able to take advantage.

The bad news: no more EIS or VCT for ROC or RHI projects

The Budget announced some unwelcome changes for investors in renewables projects.  It states that, from the date on which the new Finance Act receives Royal Assent, it will not be possible for investments in companies benefiting from Renewables Obligation Certificates (ROCs) and/or the Renewable Heat Incentive scheme to benefit from the EIS, SEIS or VCT tax reliefs.

The Budget further noted that Government “is concerned about the growing use of contrived structures to allow investment in low-risk activities that benefit from income guarantees via government subsidies and will therefore explore a more general change to exclude investment into these activities, consulting with stakeholders. The government is also interested in exploring options for venture capital reliefs to apply where investments are in the form of convertible loans, and will be considering this as part of a wider consultation and evidence gathering exercise over summer 2014”.

This is not the first time that the scope of the EIS and VCT schemes has been narrowed with respect to projects benefiting from renewables subsidies.  The Finance Act 2012 removed EIS and VCT relief from investments in businesses benefiting from Feed-in Tariffs (FIT).  However, the 2012 Act made an exception for certain bodies which are subject to constitutional restrictions on the distribution of profits – namely community interest companies (CICs) and certain “asset-locked” community benefit and co-operative societies.  Investors in these were still permitted to benefit from the EIS and VCT schemes.

But good news for social investors

The exempting of CICs and asset-locked co-operative and community benefit societies from the exclusion of FIT-supported projects from EIS and VCT relief in 2012 was in part an acknowledgement of the fact that the generation of electricity from renewable sources is the sort of activity which could qualify a business to be set up as, for example, a CIC.  There is a clear benefit to the wider community in the avoidance of greenhouse gas emissions associated with coal or gas-fired generating plant, and for smaller scale renewables projects, the CIC structure is an obvious way of involving local host communities and enabling them to receive financial benefits from a renewable development.  For an overview of the CIC regime, see our September 2013 briefing, Community Benefits Incorporated.

The Government is keen to promote community involvement in energy schemes, so it comes as no surprise that, just as EIS / VCT is removed from non-FIT projects, Budget 2014 offers an alternative route to tax relief for those who are prepared to live with any of the varying levels of restrictions on distribution of profits associated with investments in CICs, asset-locked community benefit and co-operative societies, or charities.  Schedules 9 and 10 to the current Finance Bill set out a new scheme of social investment (SI) relief which bears more than a passing resemblance to the EIS regime in particular.  FIT-supported schemes (but not ROC- or CfD-supported ones) are specifically excluded from the new SI relief but will presumably be able to continue to rely on the EIS and VCT schemes.

Of the various forms of business that may attract the new SI relief, CICs probably have the most to offer to any investors who expect to see a return on their money, rather than simply engaging in tax-efficient philanthropy.  The announcement late last year by the Regulator of CICs of a significant liberalisation of the existing rules on dividend payments by CICs is a further advantage – although dividends remain restricted to a proportion (35%) of distributable profits.

The new SI relief will deliver the same rate of relief as the EIS scheme (30%).  While the other restrictions applicable to CICs and the other kinds of businesses which are eligible for SI relief will mean that it is not an effective substitute for all types of investors in renewables projects who have benefited from the EIS and VCT schemes, those who are not looking for spectacular returns and are prepared to make the initial investment in reconciling the relevant Finance Bill provisions with the CIC regulatory regime, may find SI relief an option worth considering.

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Themes from Budget 2014 (2): investment in renewables projects – a boost for communities?

Market investigation: just what UK energy markets need?

It has been widely reported that Ofgem has referred the “Big 6” UK energy companies for investigation by the Competition and Markets Authority (CMA).  That is of course not strictly true, for three reasons.

  • First, and most trivially, the CMA, which will take over the functions of the former Office of Fair Trading (OFT) and Competition Commission, currently only exists in “shadow” form, and does not assume its statutory functions until next month.
  • Second, although the prospect of a market investigation reference has been canvassed for some time, Ofgem have not yet made a reference.  They are consulting on a proposal to do so.  The consultation ends on 23 May 2014.  As any administrative lawyer will tell you, a decision-maker must not consult with a closed mind, so we are probably still at least 3 months away from the start of a CMA investigation.  It would be possible for Ofgem to agree “undertakings in lieu of a reference” from players in the market if it felt that would adequately address the problems it is concerned about without the need for a market investigation – although at present that seems an unlikely outcome.
  • Third, as is normal with a market investigation, the proposed terms of reference do not refer to individual companies.  What Ofgem proposes that the CMA should investigate is no more and no less than the supply and acquisition of energy (i.e. electricity and gas) in Great Britain.

Market investigations are the oldest and in some ways the most powerful tool in UK competition law.  In their modern form they are governed by the Enterprise Act 2002, a piece of legislation enthusiastically promoted by the then Chancellor, Gordon Brown, as destined to make the UK economy more competitive by the more vigorous application of competition law.  They exist to deal with markets which appear to be insufficiently competitive, but whose problems do not appear to come from cartels or other anti-competitive agreements between firms, or the abuse of a dominant position – all of which obviously anti-competitive kinds of behaviour are prohibited under UK and EU law in any event.  A market investigation aims to find other features of a market which prevent, restrict or distort competition and then to devise a means or remedying, preventing or mitigating those effects, taking account of any incidental benefits which those features may bring to customers.  In a regulated market such as gas or electricity, the CMA may also need to have regard to the statutory functions of the sectoral regulator concerned.   The powers which the CMA can deploy in devising remedies for any problems it finds are extremely wide, and – unless Ministers legislate under the Act to give themselves a role – are formulated and imposed without any political sanction.  They can include everything from price regulation to divestment of a business – such as the forced sale of Stansted Airport that took place following a market investigation into airports.

Back in 2002, it was expected that there would be between two and four market investigation references a year.  In fact there have been slightly fewer: 17 completed investigations.  Back in 2002, some questioned whether economic sectoral regulators such as Ofgem would ever use the power that was being given to them to make a market reference in respect of their own sectors (otherwise, the power to refer a market rests with the OFT, or, in an extreme case, Ministers): would referring the market that it was their function to regulate not look like an admission of defeat?  Ofgem’s proposed reference, if made, will be the first to be made by an economic regulator into the very heart of the markets which it is responsible for regulating.

Ofgem have published a consultation on the proposal to make a reference and, separately, a state of the market assessment containing the fruits of its own investigation, with the OFT and CMA, into the current state of competition in energy markets.  Both are well worth reading (as is the Secretary of State’s statement to Parliament on the Ofgem announcement).  Don’t be put off by the apparent length of the state of the market assessment, as a large amount of its more than 100 pages is taken up with rather striking graphs and charts.  I particularly liked Figure 14, which shows that the proportion of consumers who said they have not switched supplier because they are “happy with their current supplier” fell from 78% in 2012 to 55% in 2013; the proportion who claimed to have checked prices and found that they were on the best deal rose from 9% to 12%; and the proportion of those honest enough simply to say that switching was too much of a hassle rose from 20% to 27%.

The points that Ofgem have highlighted as reasons for proposing a market investigation are mostly what economists would regard as potential symptoms of competition problems rather than the actual features of the market that are giving rise to those problems.  They are, however, symptoms traditionally associated with uncompetitive oligopolies, which is what market investigations are meant to be good at tackling: high levels of apparent customer dissatisfaction, but low levels of customer switching; static market shares of incumbent firms; possible “tacit collusion” (e.g. co-ordinating in the timing and size of price changes); possibly high profits; and potential barriers to entry.  The last of these is the most significant, but the assessment document is notably circumspect in its conclusions: “In the time available…we have not been able to examine in depth the claimed benefits and reasons for vertical integration for the suppliers and the implications for barriers to entry, and assess the net impact on consumers of vertical integration overall.”.

The big question of the effect of the Big 6’s high shares of both the supply and generation markets is therefore left for the CMA to consider in the greater depth that its procedures and wider powers to compel the provision of information allow.  Another big question in any regulated market is of course the effect that regulation itself has on competition.  Here, the CMA will really have its work cut out, because the regulatory landscape in the energy sector is in a more than usually fluid state just now, with various significant Ofgem reforms about to take effect and DECC in the process of finalising the radical upheaval that is Electricity Market Reform (EMR).  The CMA will have a ring-side seat as the first allocations of EMR Contracts for Difference take place and the EMR Capacity Market is launched, expected to be later this year.

That in turn raises the question of timing.  Some have been calling for an energy market investigation for some time.  Others suggest that with so much change, such an investigation can only add to uncertainty and further inhibit decision-making on new infrastructure that is sorely needed to keep the lights on.  What is certain is that market investigations can, and frequently do, take up to two years (not counting any further time taken up in legal challenges to the outcome).  There are often good reasons for that, but even apparently uncompetitive markets can change over time.  What appear to be problems at the start of an investigation may not still be there at the end.  How relevant will the CMA’s findings be in 2016, a year after an election that may be won by a Labour Party which has announced its intention of making a series of further regulatory changes, including the abolition of Ofgem and the separation of generation and supply businesses?  In any event, if the CMA do find that there are features of the regulation of energy markets that are part of the competition problem, that is one area in which it may not be able to impose remedies, and may instead have to limit itself to making recommendations to the sector regulator or the Government of the day.  So those welcoming Ofgem’s announcement as an end to “the politics” around the issues and the start of a dispassionate, technocratic process may have spoken too soon.

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Market investigation: just what UK energy markets need?

Strategies for community energy

On 27 January 2014 DECC published its first Community Energy Strategy (the Strategy). The Strategy seeks to promote the creation of new initiatives and expand existing programmes to encourage community-led development in the UK’s energy industry. The stated ambition of the Government, developed from its commitment to community-led renewable development in the Coalition Agreement, is “that every community that wants to form an energy group or take forward an energy project should be able to do so”.

The Strategy, published following the Government’s review of responses to a call for evidence, issued in June 2013, identifies four areas in which the Government wishes to promote and support communities: generation, energy efficiency, managing energy and purchasing energy.  It recognises that given the diversity of needs and geographies there can be no one size fits all approach for community development. This is captured in the varied support to be made available. As an example, the Strategy envisages that the Cheaper Energy Together scheme will continue to support energy purchasing collectives, but also paves the way for larger projects, announcing the Government’s commitment to consult on raising the maximum capacity for Feed-in Tariffs from 5MW to 10MW.

The Strategy foresees that community involvement will increase through vital partnerships with developers, investors, local authorities and regulators. In addition, it seeks to tackle some of the main challenges communities currently face:  limited access to funding, a lack of knowhow and understanding of energy projects and dealing with the regulatory processes. A new £10 million Urban Community Energy Fund will be set up to provide finance for planning electricity and heat generation projects in England which will be in addition to the existing DECC/ DEFRA Rural Community Energy Fund already established in June 2013. Similar funding schemes are available in Scotland and Wales.

The next key challenge is to build the levels of understanding and knowledge. A ‘One Stop Shop’, developed with community energy groups, for knowledge sharing and ideas will go towards bridging the knowledge gap. But more than this is needed for the community projects to navigate their way through the regulatory and commercial minefield that is the UK’s energy industry and to ensure sufficient buy-in from the wider community to support community energy projects. In addition, it will be interesting to see how the concept of the Licence Lite, an alternative electricity supply licence, with reduced supply obligations, will be developed to enable community projects to supply electricity to the community.

This Strategy comes at a time when the energy industry itself is doing more to engage local communities in new energy developments: the shale gas and oil industry presented a package of benefits for communities located near fracking sites in its Community Engagement Charter in the Summer of 2013. Whilst RenewableUK updated its Community Benefits Protocol in October 2013, which commits developers of qualifying projects to providing certain levels of benefits to host communities. DECC’s plan, however, is for communities themselves to play a greater part in developing local energy strategy, and ultimately it is the extent to which the public is made aware of the resources available and the take-up of those resources, which will determine whether the Strategy achieves its aim.

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Strategies for community energy