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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

Something for everyone? The European Commission’s Winter “Clean Energy” Package on Energy Union (November 2016)

On 30 November 2016, the European Commission officially unveiled the latest instalment of its ongoing Energy Union initiative, which will reform some of the central pieces of EU energy legislation.  Referred to in advance as the “Winter Package” (not to be confused with the rather more limited package released in February 2016), it has been published as the “Clean Energy for all Europeans” proposals and is the most significant series of proposals yet to emerge under the Commission’s “Energy Union” brand.  It will have far-reaching implications within and potentially beyond the existing EU single energy market.

There is a lot to consider in these proposals, and we will return to some of the issues they raise in more depth and from other perspectives in future posts. What follows is an overview and some initial thoughts from a predominantly UK-based viewpoint.

Important though it is, many of the Winter Package’s proposed reforms are evolutionary rather than revolutionary.  Some could even be criticised for lacking ambition.  The Commission’s proposals certainly provide opportunities for newer technologies such as storage and demand side response and for those seeking to make use of newer commercial models such as aggregation or community energy schemes, but all these groups are still likely to need to work hard in many cases to exploit the leverage that the new rules would give them.  It is interesting that what has been picked up most in early news reports of the Winter Package is the Commission’s move to end subsidies for coal-fired plant.  This is a significant step, but it is only one part of a complex and multi-layered set of draft legislative measures, and is one of the few instances in those measures of a provision that overtly tilts the playing field in favour of or against a particular technology in a new way.

The story so far

Let’s begin by reminding ourselves what Energy Union is about. The project is said to have five “dimensions”.  These are:

  • Security, solidarity & trust: the buzz-words are “diversification of supply” and “co-operation between Member States” – all informed by anxieties about over-dependence on Russian gas.
  • A fully-integrated internal energy market: going beyond the 2009 “Third Package” of gas and electricity market liberalisation measures (and their ongoing implementation through the promulgation of network codes) to achieve genuine EU-wide single gas and power markets.
  • Energy efficiency: using less energy can be hard, but it is the best way to meet environmental objectives and it can also be a significant source of new jobs and economic growth.
  • Climate action – decarbonising the economy: signing and ratifying the Paris CoP21 Agreement was the easy bit.  How is the EU going to achieve deep decarbonisation of not only its power but also its heat and transport sectors so as to meet its UNFCCC obligations?
  • Research, innovation & competitiveness: can European businesses still take the lead in developing technologies that will save the planet, and also make money out of commercialising them?

In other words, Energy Union is about everything that matters in EU energy policy.  To date, at least in relation to electricity markets, the initiative has involved a lot of consultation but not many concrete legislation proposals.  The new Winter Package goes a long way towards redressing this balance, but it shows there is still a lot of work to do.

What is in the Winter Package?

The documents published by the Commission (all available from this link) include legislative proposals and a range of explanatory and background policy documents.  The legislative proposals are for:

We comment below on what seem to us at this stage to be the most interesting points in these, and also on the Communication on Accelerating Clean Energy Innovation (the Innovation Communication).

The Revised IMED

Overall impressions

The legislative elements of the Winter Package are all inter-related, but the Revised IMED is as good a place to start as any.  Its early articles include two programmatic statements:

  • National legislation must “not unduly hamper cross-border flows of electricity, consumer participation including through demand-side response, investments into flexible energy generation, energy storage, the deployment of electro-mobility or new interconnectors”.
  • Electricity suppliers must be free to determine their own prices.  Non-cost reflective power prices should only apply for a transitional period to vulnerable customers, and should be phased out in favour of other means of support except in unforeseeable emergencies.

In some ways, this sets the tone for the more specific provisions that follow.  It often seems that the Commission never loses an opportunity to put forward legislation in the form of a directly applicable Regulation rather than in the form of a Directive that by definition requires Member States to take implementing measures in order fully to embed its effect within national regulation.  However, the revised IMED, like its predecessor, stands out as a classic old-school Directive, in which EU legislators tell Member States lots of results to be achieved, but do not prescribe many of the means by which this is to happen.  Moreover, even the expression of those objectives is (inevitably) qualified: in other words, get rid of the barriers to the Commission’s vision of Energy Union, except the ones you can justify.  Of course, that is slightly unfair: as noted below, there are at least one or two eye-catching points in the revised IMED, and there are significant changes proposed in other parts of the Winter Package that should further the objectives of the revised IMED, but it arguably demonstrates less willingness to get to grips with some of the most difficult of the longer-term and more fundamental changes in the market than the call for evidence on moving towards a smart, flexible energy system that was published on 10 November by the UK government and GB energy regulator Ofgem (although admittedly the UK authorities are only asking questions, not proposing solutions at this stage).

A market for consumers (and prosumers)

The revised IMED would enhance the rights of consumers generally in a variety of ways.  For example:

  • Price increases are to be notified and explained in advance, giving them the opportunity to switch before an increase takes effect.  Switching must take no longer than three weeks.
  • Termination fees may only be charged where a fixed term contract is terminated prematurely, and must not exceed the direct economic loss to the supplier.
  • All consumers are to be entitled, on request, to a “dynamic electricity price contract” which reflects spot market price fluctuations at least as frequently as market settlement occurs.  They will of course need smart meters to make this work (see further below).
  • All consumers are to be entitled to contract with aggregators, without the consent of their supplier, and to end such contracts within three weeks.

In addition, special consideration is given to two newly defined categories of persons.

  • “Active consumers” are defined as individuals or groups “who consume, store or sell electricity generated on their premises, including through aggregators, or participate in demand response or energy efficiency schemes”, but who do not do so commercially / professionally.
  • “Local energy communities” are defined as organisations “effectively controlled by local shareholders or members, generally non-profit driven or generally value rather than profit-driven…engaged in local energy generation, distribution, aggregation storage, supply or energy efficiency services, including across borders”.

Active consumers are to be:

  • entitled to undertake their chosen activities “in all organised markets” without facing disproportionately burdensome procedures or charges; and
  • encouraged to participate alongside generators in all organised markets.  Obviously in most cases they will do this through aggregators, who are to be treated “in a non-discriminatory manner, on the basis of their technical capabilities”.  For example, they are not to be required to pay compensation to suppliers or generators (contrary to some of the suggestions in the UK call for evidence referred to above).

Local energy communities:

  • are similarly not to be discriminated against;
  • may “establish community networks and autonomously manage them” and “purchase and sell electricity in all organised markets”;
  • must not make participation in a local energy community compulsory, or limit it to those who are shareholders in or members of the community; and
  • will be subject to the unbundling rules for distribution system operators if they are DSOs.

As in the original Directive 2009/72/EC, there are provisions requiring improvements to customer billing and encouraging the rollout of smart meters.

  • Customers should receive bills once a month where remote reading of the meter is possible.
  • Where a Member State has decided not to mandate smart meters for cost-benefit reasons, they are to revisit their assessment “periodically” and report the results to the Commission.
  • The draft Directive sets out functionalities that smart meters must include where a Member State mandates their rollout.  In such cases, the costs of smart metering deployment are to be shared between all consumers.  In other cases, every customer is entitled, on request, to receive a smart meter that complies with a slightly reduced set of functionalities.
  • The implementation of smart metering must encourage active participation of consumers in the electricity supply market (although this may be qualified by a cost-benefit analysis).
  • There are a number of provisions reflecting both concerns about cybersecurity and the importance of making useful data securely available to legitimate market participants.

DSOs (and EVs)

There has been no shortage of recent commentary on how the shift towards decentralised generation of electricity, combined with the potential for storage and more active consumer behavior, may require changes in the role of the 2,400 market participants that the IMED has always called distribution system operators, but which in many jurisdictions have historically not had, even within their own networks, the kind of “system operator” responsibilities of a transmission system operator.  The recent UK call for evidence on flexibility appears at least prepared to contemplate some significant realignment of the respective functions of DSOs and TSOs.  There is nothing so fundamental in the revised IMED, but there are a number of new provisions about DSOs.

  • DSOs are to be allowed, and incentivised, to procure services such as distributed generation, demand response and storage in order to make their networks operate more efficiently.  DSOs will be paid for this, and must specify standardised market products for these services.
  • Every two years, DSOs must update five to ten year network development plans for new investments, “with particular emphasis on the main distribution infrastructure which is required…to connect new generation capacity and new loads including re-charging points for electric vehicles”, as well as demand response, storage, energy efficiency etc.
  • DSOs serving isolated systems or fewer than 100,000 consumers can be excused from this requirement, but note that in general, those operating “closed distribution systems” are to be subject to the same rules as other DSOs under the revised IMED.

However, although DSOs are to facilitate the adoption of new technologies, such as storage and EVs, they are not encouraged to diversify into actually providing them to end users themselves.

  • Member States are to facilitate EV charging infrastructure from a regulatory point of view, but DSOs may only “own, develop, manage or operate” EV charging points if the regulator allows them to after an open tender process in which nobody else expresses an interest in doing so.  And even then, the service taken on by the DSO must be re-tendered every five years.
  • Similar rules would apply to the development, operation and management of storage facilities by either DSOs or TSOs.  For TSOs, there would be an additional requirement that the storage services or facilities concerned are “necessary” to ensure efficient and secure operation of the transmission system, and are not used to sell electricity to the market.

What makes these provisions significant is that until now, with the IMED in its original form silent on the subject of storage, the operation of storage facilities had been seen as potentially falling within the categories of generation or supply.  This appeared to make the involvement of DSOs or TSOs in storage projects (at least as investors) subject to the general unbundling restrictions, and so has tended to inhibit the progress of energy storage initiatives in a number of cases.  The proposed new rules are restrictive in some respects, but bring a degree of clarity and at least recognise storage as a distinct category.

The Revised Market Regulation

General organisation of the electricity market

Like the revised IMED, the Revised Market Regulation begins with firm statements of purpose: enabling market access for all resource providers and electricity customers, enabling demand response, aggregation and so on.  It goes on to list 14 “principles” with which “the operation of electricity markets shall comply” – starting with “prices are formed based on demand and supply” and finishing with “long-term hedging opportunities allow to hedge parties against price volatility risks”.

Entirely in keeping with these principles, the first specific provision is that all market participants are to be responsible for (or to delegate to a responsible third party) the consequences of any imbalance they create in the electricity system as a result of importing or exporting to or from the grid at a given time more or less than they had said would be the case at that time in previous notifications to the system operator.  This much-trailed provision may be a significant change for renewable generators in some jurisdictions (though not in GB, where imbalance charging reforms are already being implemented).  In an earlier draft, the Revised Market Regulation only permitted sub-500kW renewables or high-efficiency CHP to be exempted from this requirement.  In the published version, this exemption has been broadened to include RES projects that have received state aid that has been cleared by the commission and that have been commissioned before the Revised Market Regulation enters into force.  It also requires that “all market participants” are to have access to the balancing market on non-discriminatory terms, either directly or through aggregators.

There are a number of quite detailed provisions on the overall organisation of electricity markets. We pick out a few of the more notable ones below.

  • There is a shift from a national to a regional approach.  As the explanatory memorandum to the draft Directive puts it: “In certain areas, e.g. for the EU-wide ‘market coupling’ mechanism, TSO cooperation has already become mandatory, and the system of majority voting on some issues has proven to be successful…Following this successful example, mandatory cooperation should be expanded to other areas in the regulatory framework.  To this end, TSOs could decide within ‘Regional Operational Centres’…on those issues where fragmented and uncoordinated national actions could negatively affect the market and consumers (e.g. in the fields of system operation, capacity calculation for interconnectors, security of supply and risk preparedness).”.  Functions to be carried out at a regional level include “the dimensioning of reserve capacity” and “the procurement of balancing capacity”.
  • As far as possible, the organisation of markets is to avoid any rules that could restrict cross-border trading or the participation of smaller players.  So, for example, trades are to be anonymous and in a form that does not distinguish between bidders within and outside a bidding zone.  The minimum bid size is not to exceed 1 MW.
  • Market participants are to be able to trade energy as close to real time as possible, with imbalance settlement periods being set to 15 minutes by 1 January 2025.
  • Long-term (firm, and transferable) transmission rights or equivalent measures are to be put in place to enable e.g. renewable generators to hedge price risks across bidding zone borders.  Such rights are to be allocated in a market-based manner through a single allocation platform.
  • As a general rule, there must be no direct or indirect caps or floors on wholesale power prices, other than a cap at the value of lost load and a floor of minus €2000, or during a 2-year transitional period when a transitional maximum and minimum clearing price may be allowed.  Defined as “an estimation in €/MWh of the maximum electricity price that consumers are willing to pay to avoid an outage”, the value of lost load is to be defined nationally and updated at least every five years.  This concept will evidently need refinement, as there is a difference between what individual consumers may be prepared to pay and the kind of price spikes that it is reasonable for wholesale markets to bear for short periods of time.
  • Dispatching of generation and demand response is to be market-based.  Priority dispatch for renewables is to be brought to an end subject to certain exceptions (these are summarised in the section on the revised RED below).  On the other hand, where redispatch (changing generator output levels) or curtailment is imposed by the system operator other than on market-based criteria, the draft Regulation imposes restrictions on when RES, high-efficiency CHP and self-generated power can be redispatched or curtailed.
  • There is to be a review of the bidding zones within the single electricity market, so as to maximise economic efficiency and cross-border trading opportunities while maintaining security of supply.  In other words, the market coupling process should allow customers to benefit from the availability of lower-priced wholesale power in adjacent markets, but the bidding zone boundaries need to take account of “long-term structural congestion” in the network infrastructure for this to be workable and without adverse side-effects.  TSOs are to participate in the review, but the final decisions are to be taken by the Commission.
  • A significant piece of work is to be undertaken by ACER on “the progressive convergence of transmission and distribution tariff methodologies”.  This is to include, but not be limited to, some issues that have recently proved contentious in the GB context, including the respective shares of tariffs to be paid by those who generate and those who consume power; locational signals (how much more should generators pay if they are located a long way from where the power they generate used); and which network users should be subject to tariffs (would this, for example, open up the question of whether generators connected to the distribution network should pay a share of transmission network charges?).
  • Separately, the draft Regulation sets out some general principles about network charges and restricts both the circumstances in which revenue can be generated from congestion management and the uses to which such revenue can be put.

Resource adequacy (a.k.a. Capacity Markets)

The growth in the share of installed generating capacity in many Member States represented by intermittent renewable generators and the unattractive economics of new large-scale combined cycle gas-fired plant has left many governments in the EU concerned about security of power supply and turning to various forms of capacity market subsidy in order to ensure that the lights stay on.  The Commission has been concerned that capacity markets dampen the price signals that should drive new investment and potentially introduce new barriers to cross-border power flows.  A number of national capacity market regimes have been investigated by the Commission’s DG Competition; both the UK and French approaches to the problem have received state aid clearance.

The starting point of the draft Regulation in this area is an annual assessment of “the overall adequacy of the electricity system to supply current and projected demands for electricity ten years ahead”.  This European-level assessment will form the yardstick against which national proposals to introduce a capacity mechanism are to be judged.  If it has “not identified a resource adequacy concern, Member States shall not introduce capacity mechanisms” and no new contracts shall be concluded under existing capacity mechanisms.  Where capacity mechanisms are introduced, they must not distort the market unnecessarily; interconnected Member States should be consulted; and other approaches, such as interconnection and storage, should be considered first.

The draft Regulation prescribes common elements which capacity mechanisms must contain, including that they must be open to providers in interconnected Member States (unless they take the form of strategic reserves) and that the authorities of one country must not prevent capacity located in their territory from participating in other countries’ capacity mechanisms.  Those participating simultaneously in more than one capacity mechanism “shall be subject to two or more penalties if there is concurrent scarcity in two or more bidding zones that the capacity provider is contracted in”.  Maybe that will help to dampen industry’s appetite for capacity markets.

Finally, the draft Regulation sets an emission limit of 550 gCO2/kWh for plant on which a final investment decision is made after the Regulation enters into force.  Such plant must have emissions below this limit if it is to be eligible for capacity mechanism support.  The draft Regulation goes on to state that generation capacity emitting at this level or higher is “not to be committed in capacity mechanisms 5 years after the entry into force of this Regulation”.  These provisions may be motivated by laudable decarbonisation objectives, but they must at the very least risk precipitating a rush to take final investment decisions in new coal-fired generating capacity over the next two years.  It is possible, but unlikely, that they might stimulate further investment in carbon capture and storage (to bring the emissions of coal-fired plants below the threshold).  Previous experience with emissions limit rules also suggests that much will depend on how emissions are measured – the usual trick of polluting plant being to argue that they should be counted not per hour of generation, but averaged out over time so as to allow for plant to run above the limit for short periods.  This is bound to be an area for lively negotiations between Member States and in the European Parliament.

The Commission’s proposals in relation to capacity markets need to be read alongside DG Competition’s final report on its investigation and the accompanying Staff Working Paper.  We will look in more detail at this aspect of the proposals and how it might affect existing Member State initiatives in a future post.  For now, it is sufficient to note that although this part of the Winter Package is entirely consistent with the logic of the evolving single electricity market, for some, it may simply appear to be an unacceptable blow to the principle of Member States’ self-determination of their own generating mix.

Institutions

In addition to its existing roles, the TSO umbrella body, ENTSO-E, will acquire new responsibilities for the European resource adequacy assessment and in relation to the Regional Operational Centres, including adopting a proposal for defining the regions which each will cover, and generally monitoring and reporting on their performance.  A parallel umbrella body for DSOs, with consultative functions, is also to be set up.

The draft Regulation devotes a number of articles to the Regional Operational Centres. They will be limited liability companies established by TSOs (with adequate cover for potential liabilities incurred by the impact of their decisions).  Their role is to complement TSO functions by ensuring the smooth operation of the interconnected transmission system, but apparently from the perspective of planning and analysis rather than real-time  operational control.  Specific areas of their work (listed under 17 headings) include outage planning coordination, calculating the minimum entry capacity available for participation of foreign capacity in capacity mechanisms, and much else besides.

This area of the draft Regulation will need careful development and implementation if the proliferation of new bodies and functions is not to result in confusion and a lack of accountability.  However, the question of whether to grant Regional Operational Centres binding decision-making powers in relation to some of their potential functions is left to be decided by the national regulatory authorities of a system operating region.

The Revised RED

Target for 2030

The existing Renewable Energy Directive (2009/28/EC) sets out the binding national targets for each Member State to achieve a specified proportion of its energy consumption to be obtained from renewable energy sources (RES) by 2020, contributing to an EU-wide goal of 20% of final energy from RES.  The revised RED starts from a slightly different point, since EU leaders decided in 2014 to move away from legally binding national RES targets imposed at EU level but to set a goal of achieving at least 27% of energy from RES across the EU by 2030.  The starting point of the revised RED, therefore, is that “Member States shall collectively ensure” that the 27% target is achieved by 2030, whilst, individually, ensuring that they continue to obtain at least as high a proportion of final energy from RES as they were obliged to achieve by 2020.

At this point, you may ask what the enforcement mechanism is for meeting the new EU-wide target.  An answer (of sorts) is to be found in the Governance Regulation – see below.

Power (plus)

With reference to subsidies for RES, the revised RED builds on the principles set out in the Commission’s 2014 guidelines on state aid in the energy and environmental sectors: competitive auctions in which all technologies can compete on a level playing field are to be the norm, with traditional feed-in tariffs limited to small projects.

The revised RED also makes provision on two points that have led to disputes in connection with RES subsidies.  First, picking up on a point that has in the past given rise to litigation under general EU Treaty principles, it would set quotas for the proportion of capacity tendered in RES subsidy auctions that each Member State must throw open to projects from other Member States.  Second, with an eye to the numerous cases brought against Member States either under domestic constitutional / administrative law or under the Energy Charter Treaty, the revised RED attempts to outlaw retrospective reductions in support for RES once that support has been awarded, unless these are required because a state aid investigation by the Commission has found the subsidy received by a project is unduly generous.  Note that while the first of these rules appears to relate only to RES electricity subsidies, the second is expressed in a way that suggests that it relates to all RES projects.   An additional measure of reassurance for investors is a requirement to consult on and publish “a long-term schedule in relation to expected allocation for [RES] support” looking at least three years ahead.

Other points of interest in the draft Directive in connection with RES power include:

  • In a magnificently brief reference to one of the most important market trends in the renewable power sector, the revised RED would require Member States to “remove administrative barriers to corporate long-term power purchase agreements to finance renewables and facilitate their uptake”.
  • The process of applying for permits to build and operate new RES projects is to be streamlined, with a single point of contact co-ordinating the permitting process (including for associated network infrastructure) and ensuring that it does not last longer than three years.  This provision would confers on all RES projects (again, the current language of the draft Directive does not limit this to power sector projects) a benefit currently only conferred at EU level under the Infrastructure Regulation on those projects singled out as Projects of Common Interest – although in its current form it is questionable if it would give a developer thwarted by slow decision-making in a given case a useful remedy.
  • The permitting procedures for repowering of existing projects are to be “simplified and swift” (i.e. not to last more than 1 year), although this may not apply if there are “major environmental or social” impacts.  If you were hoping to be able to demand fast-track treatment for applications to repower existing wind farms with fewer, taller turbines generating more power, don’t hold your breath.
  • The existing RED rules on priority dispatch for RES generators are to be abolished.  This point is reiterated in the Revised Market Regulation.  However, that draft Regulation provides for “grandfathering” of priority dispatch rights for existing RES (and high efficiency CHP) generators until such time as they undergo “significant modifications”.  Exceptions are also permitted for innovative technologies and sub-500kW installations (from 2026, sub-250kW), if no more than 15% of total installed generating capacity in a given Member State benefits from priority dispatch (beyond that level, the threshold is 250kW or 125kW from 2026).
  • The revised RED likes prosumers, or as it calls them, “renewable self-consumers”.  They are to be entitled to sell their surplus power “without being subject to disproportionate procedures and charges that are not cost reflective”, to receive a market price for what they feed into the grid, and not to be regulated as electricity suppliers if they do not feed in more than 10MWh (as a household) or 500MWh (as a business) annually (Member States may set higher limits).
  • The revised RED also likes “renewable energy communities”.  The draft definition of these is a little complicated, but essentially they are locally based entities that are either SMEs or not for profit organisations, which are to be allowed to generate, consume, store and sell renewable electricity, including through PPAs.

Heat, cooling and transport

The revised RED seeks to “mainstream” RES in heating and cooling installations, and in the transport sector.  The means by which it seeks to achieve this are not, at first sight particularly dramatic, given the acknowledged scale and difficulty of the challenge of decarbonising these sectors.

In relation to heat and cooling, Member States are to identify “obligated parties amongst wholesale or retail energy and energy fuel suppliers” and require them to increase the share of RES in their heating and cooling sales by at least 1 percentage point a year.  The obligation should be capable of being discharged either directly or indirectly (including by installing or funding the installation of highly efficient RES heating and cooling systems in buildings).  This does not seem hugely ambitious.  Mention is made of “tradable certificates” – it feels a bit like a combination of the Renewables Obligation, but applied to heat and cooling, and the Clean Development Mechanism under the Kyoto Protocol.  It is also relevant in this context that the revised RED envisages that renewable guarantees of origin (REGOs or GoOs) will in future be available for the production and injection into the grid of renewable gases such as biomethane.

The rules aimed at the transport sector are also based on mandatory requirements on fuel suppliers – in this case to incorporate both a minimum (annually increasing) percentage of certain kinds of RES fuel, waste-based fossil fuel and RES electricity into the transport fuel they supply and to ensure that the parts of that supply that take the form of advanced biofuels and biogas from specified sources (which must constitute a certain part of the overall RES percentage) contribute to an increasing reduction in greenhouse gas emissions.  The provisions for calculating the various percentages are quite complex, involving as they do an element of lifecycle emissions calculation (e.g. considering the emissions from the generation of electricity used to produce advanced biofuels).

On district heating and cooling, the revised RED takes a three-pronged approach.

  • Member States are to ensure that authorities at local, national and regional level “include provisions for the integration and deployment of renewable energy and the utilisation of unavoidable waste heat or cold when planning, designing, building and renovating urban infrastructure, industrial or residential areas and energy infrastructure, including electricity, district heating, and cooling, natural gas and alternative fuel networks”.
  • The efficiency of district heating systems is to be certified.  Providers of such systems must grant access to new customers where they have the capacity to do so (unless they are new and meet exemption criteria based on efficiency and use of renewables).  Customers of systems that are not efficient may disconnect from them in favour of their own RES heat and cooling, but Member States may restrict this right to those who can demonstrate that the customer’s own heating or cooling solution is more efficient.
  • There is to be regular consultation between operators of district heating and gas / electricity networks about the potential to exploit synergies between investments in their respective networks.  Electricity network operators must also assess the potential for using district heating and cooling networks for balancing and energy storage purposes.

This is all unobjectionable.  It is not clear that in itself it will be enough to cause a major expansion of district heating and cooling where it does not already exist, or to significantly increase the take-up of RES heat and cooling options, but perhaps this is the kind of area where an effective policy push can only be delivered at national, or indeed municipal level.

Biomass

Following a trend that has been evident for some time in UK subsidies for RES electricity, the revised RED would appear to prohibit “public support for installations converting biomass into electricity” unless they apply high efficiency CHP, if they have a fuel capacity of 20 MW or more.  However, the precise words setting this out have been moved from the operative provisions of the draft Directive into a recital, which also clarifies that this would not require the termination of support that has already been granted to specific projects, but that new biomass projects will only be able to be counted towards renewables targets if they apply high efficiency CHP.

What is clear is that the revised RED would tighten the sustainability criteria applicable to biofuels and bioliquids at various points in the energy supply chain, with greenhouse gas emissions – for example those arising from land use to grow the raw materials that become biofuels – being designated as a distinct impact to be measured.  If you dig up soil with a high carbon content to grow something that will become biofuel, you may end up increasing rather than reducing overall GHG emissions, so this is obviously to be avoided.

The Governance Regulation

The Governance Regulation is meant to hold everything together.  In particular, it aims to give credible underpinning to the commitments on climate change that the EU as a whole has made under the Paris Agreement (but which must ultimately be delivered by Member State action) and to bridge the gap left by having an EU level 2030 renewables target but no correspondingly increased Member State level targets.  It also gives legislative expression to the EU’s Union-level energy and climate targets to be achieved by 2030, which are:

  • a binding target of at least 40% domestic reduction in economy-wide greenhouse gas emissions as compared with 1990;
  • a binding target of at least 27% for the share of renewable energy consumed in the EU;
  • a target of at least 27% for improving energy efficiency in 2030, to be revised by 2020, having in mind an EU level of 30%;
  • a 15% electricity interconnection target for 2030.

In outline, the Regulation works as follows.

  • Every 10 years, starting in 2019, each Member State is to produce an integrated national energy and climate plan covering a period of ten years, two years ahead (so e.g. the 2019 plan covers 2021 to 2030, and so on).  The plan is to set out, in relation to each of the five dimensions of the Energy Union, the current state of play in the relevant Member State; the national objectives and targets, policies and measures they have adopted; and their projections (including in relation to emissions) going forward to 2040.  The draft Regulation sets out in considerable detail the information which is required to be included.
  • In relation to RES and energy efficiency, Member States are expressly required to take into account the need to contribute towards achieving the relevant EU level targets, and to ensure, collectively, that they are met.  In relation to RES policies, they are also to take into account “equitable distribution of deployment” across the EU, economic potential, geographic constraints and interconnection levels.
  • The draft Regulation states that Member States must consult widely on the plans and suggests that there may also be a need for the preparation of and consultation on a strategic environmental assessment of the draft plans in some cases.
  • Every two years (starting in the first year to which the plans apply), Member States are to report to the Commission on the status of implementation of their plans; on GHG policies, measures and projections; on climate change adaptation and support to developing countries; on progress in relation to renewable energy, energy efficiency and energy security; on internal market benchmarks such as levels of interconnectivity; and on public spending on relevant research and innovation projects.  In addition, the draft Regulation specifies how Member States are to report annually on GHG inventories for UNFCCC purposes.
  • The plans and drafts are to be updated if necessary after five years (with the first draft update in 2023 and the first update in 2024), using the same procedures.  Updates cannot result in Member States setting themselves lower targets.
  • The plans are first to be submitted to the Commission for comment one year in advance, in draft (i.e. first draft by 1 January 2018).  Either at this point or in its annual State of the Energy Union reports, the Commission may make recommendations to individual Member States, for example about “the level of ambition of objectives and targets” in its draft plan, and Member States “shall take utmost account” of these when finalising the plan.  Member States are obliged to issue annual progress reports on their plans and these must include an explanation of how they have taken utmost account of any Commission recommendations and how it has implemented or intends to implement them.  Any failure to implement the Commission’s recommendations must be justified.
  • Member States whose share of RES falls below their 2020 baseline must cover the gap by contributing to an EU-level fund for renewable projects.  If it becomes clear by 2023 that the 2030 RES target is not going to be met, Member States must cover the gap in the same way, or by increasing the percentage of RES fuel to be provided by heat and transport fuel suppliers under the revised RED, or by other means.  Action may also be taken by the Commission at EU level.

The answer to the question of how the 2030 targets are enforced is therefore – and perhaps inevitably – somewhat incomplete.  Whilst one may doubt the usefulness, under the current RED, of the prospect of the Commission taking infraction proceedings against a Member State that fails to reach the required percentage of RES energy by 2020, there is arguably nothing in the Governance Regulation that has even this degree of legal bite when it comes to pushing recalcitrant Member States into action from the centre.  However, ultimately the whole edifice of the Paris Agreement, of which this is effectively a supporting structure, will only work on the basis of a combination of the economic attractions of better energy efficiency, cheaper renewables and other technological advances, and stakeholder pressure, including through democratic and judicial processes.  The Governance Regulation, like the UK’s Climate Change Act 2008 with its system of carbon budgets, certainly provides some scope for interested parties to challenge national authorities who are, for example, failing unjustifiably to implement Commission recommendations.

The Risk Regulation

The Risk Regulation exists to provide “a common framework of rules on how to prevent, prepare for and manage electricity crisis situations, bringing more transparency to the preparation phase and…ensuring that electricity is delivered where it is needed most”.  A common approach to identifying and quantifying risks is seen as essential to building the necessary “trust” and “spirit of solidarity” between Member States.  The draft Regulation would replace the rather less ambitious existing Directive 2005/89/EC.

ENTSO-E is tasked with developing a common risk assessment methodology, on the basis of which it is to draw up and update regional crisis scenarios such as extreme weather conditions, natural disasters, fuel shortages or malicious attacks.  Provision is made for emergency planning at both national and regional levels, with the Regional Operational Centres playing a significant role at various points.  As throughout the Winter Package, emphasis is laid on using market measures wherever possible, so that forced disconnections, for example, should be response of last resort, and Member States facing a crisis should not automatically seek to curtail outbound cross-border power flows.

The ACER Regulation

It comes as no surprise that the Winter Package proposes conferring more powers on ACER.  So, for example, the methodologies and calculations underlying the European resource adequacy assessment will require the approval of, and may be amended by, ACER – since, as one of the recitals to the draft Regulation notes, “fragmented national state interventions in energy markets constitute an increasing risk to the proper functioning of cross-border electricity markets”.  But the draft Regulation is far from representing a major transformation of ACER into an EU energy super-regulator.

The Innovation Communication

The Innovation Communication picks up on a number of the themes emphasised in the various legislative proposals.  It builds on existing initiatives, for example within the framework of the EU’s Horizon 2020 funding programme, for which it includes some new money.  The need to leverage more private sector investment in innovative energy-related technologies is noted, with some examples of where this has already been achieved.  The Communication also states that the Commission, with Member States, will take a leading role in two of the workstreams identified by the international Mission Innovation Initiative.

Four particular priorities are singled out as technology focus areas for EU innovation funding:

  • Energy storage solutions, including the (perhaps not unambitious) objective of “re-launching the production of battery cells in Europe”.
  • Electro-mobility and a more integrated urban transport system, which amongst other things will include tackling “fragmentation in the developing market of low-emission transport”.
  • Decarbonising the EU building stock by 2050: going beyond “today’s nearly zero-energy designs” to include e.g. the application of circular economy principles.
  • Integration of renewables: reducing the costs of existing established technologies; promoting new technologies like building-integrated photovoltaics; and intensifying efforts to integrate renewables through storage and the transport sector.

Energy Efficiency

Last but not least, energy efficiency. The two draft Directives on this make less wide-ranging changes to the existing legislation.

Under the revised Energy Efficiency Directive, Member States will be obliged to deliver the equivalent of 1.5% of annual energy sales (by volume) to final consumers over the period 2021-2030 – but with scope to determine how those savings are phased.

As regards the Energy Performance of Buildings Directives, there is an emphasis on encouraging the use of smart technologies.  There is also a requirement, when building or carrying out major renovations of buildings with more than 10 car parking spaces, to install one alternative fuel re-charging point for every 10 spaces in a non-residential context and to put in pre-cabling for re-charging points for EVs in all spaces in a residential context.  In the non-residential context at least, the re-charging point must be “capable of starting and spotting charging in relation to price signals”.  There are also some new requirements to monitor the energy efficiency of non-residential buildings, presumably in the hope that if their owners become aware of how much inefficiencies of design or operation are costing them, they will invest in improvements.

At the same time, the Commission has issued an ecodesign working plan for 2016-2019, reminding us as it does so that EU ecodesign and energy labelling deliver “energy savings equivalent to the annual consumption of Italy” and “save almost €500 per year” on household energy bills, as well as delivering approximately €55 billion extra revenue for industry.

Brexit

One of the many energy-sector questions raised by the UK’s decision to leave the EU is on what terms participants in the electricity markets in GB and Northern Ireland (and indeed the Republic of Ireland, until such time as it has a direct interconnection with Continental Europe) may be able to continue to participate in the EU’s single electricity market in a post-Brexit world.  Possible models for this include membership of the European Economic Area (as an EFTA, rather than an EU state) or joining the Energy Community (many of whose members are candidates for EU membership, but disputes within which are resolved by a political Association Council without reference to the Court of Justice of the EU).

The Winter Package in its published form casts no direct light on this subject.  However, in a version of the main legislative proposals that was leaked only a couple of weeks before they were published, a number of the draft measures (such as the draft revised IMED) included a couple of articles that appeared to offer some grounds for hope – if continued UK membership of the single EU electricity market is the sort of prospect that makes you hopeful.

  • Like the EU itself, the Energy Community is currently operating on (or is working towards) the version of the single electricity and gas markets set out in the Third Package of EU liberalisation measures adopted in 2009.  The leaked draft revised IMED set out a process for the Energy Community and the Commission to incorporate the revised Directive into the Energy Community’s legislative framework.  So if the UK was happy with the final form of the Winter Package legislation, the option of continuing to be subject to and getting the benefit of it as a member of the Energy Community would be a possible option.
  • On the other hand, once the UK ceases to be an EU Member State, and assuming it does not opt for EEA membership, it will simply become a “third country” (with or without the benefit of a bespoke EU / UK free trade agreement).  The leaked draft revised IMED suggested that third countries may participate in the single electricity market provided that they agree to adopt, and apply, “the main provisions” of the Winter Package legislation; EU state aid rules; the REMIT rules on wholesale energy market integrity; “environmental rules with relevant for the power sector”; and rules on enforcement and judicial oversight that require it to submit either to the authority of the Commission and the CJEU or “to a specific non-domestic enforcement body and a neutral non-domestic Court or arbitration body which is independent from the respective third country”.

Reading these provisions in the UK, it was hard not to see them as drafted with Brexit in mind.  Of course, the EU is, or aspires to be, physically connected to power systems in other non-EU countries as well (such as the potential solar energy exporters of North Africa), so it would be wrong to see them entirely in that light.

How the absence of such provisions, or the prospect of their potential reinsertion, will affect the dynamics of the UK’s participation in negotiations on the Winter Package (which is likely to take place while the UK is still a Member State) is another question.  In our view, the UK and its electricity industry stakeholders should in any event try to play a leading and constructive role in the whole of the negotiations on the Winter Package, as they have in negotiation on past internal energy market measures.

Maybe, in one sense, it is better that the draft provisions on third country participation have not been included at this stage.  Similar provisions could be negotiated on a standalone basis later, and include the gas as well as electricity single markets, for example.  By leaving them out of the Winter Package (for whatever reason), the Commission may have prevented the UK team from being unduly distracted from the main subject of the legislative proposals, or expending its negotiating capital on their Brexit dimension.

Provisional conclusions

The Winter Package covers a lot of ground, but then it needs to do so, since the next ten years are acknowledged to be crucial to the success of global efforts to avoid dangerous climate change.  It may not be as radical as some would like, but then whilst some of its requirements are already more or less met by a number of Member States, for others they may represent a considerable challenge.  In one sense it is a timely reminder of both the scope and the limitations of the European project.

There are a lot of links between the individual pieces of draft legislation.  There are also a number of areas where the drafting suggests that some key concepts have not yet been absolutely fully thought out.  Steering negotiations so as to result in a clear and coherent legal framework will be difficult.  The risks of (calculated or inadvertent) lack of clarity in the final texts may be higher than is usual with EU legislation, leading to wrangles with regulators and before the courts down the line – or simply having a chilling effect on what could be useful activity.  However, since the need for action is urgent, waiting for perfect legislation is not a luxury the EU can afford.  So it is vital that those with an interest in making Energy Union work scrutinise the parts of the Winter Package that matter to them carefully, and tell their national governments or MEPs where they find it wanting.

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Something for everyone? The European Commission’s Winter “Clean Energy” Package on Energy Union (November 2016)