ROYAL SOCIETY REPORT HIGHLIGHTS LARGE SCALE ENERGY STORAGE AS A KEY ISSUE

I was recently asked, as one of the major contributors, to comment on the recent Royal Society report on large scale energy storage. This had been a major exercise, impressively managed and directed by the lead author Chris Llewelyn Smith, involving the examination of how a UK system based on weather dependent renewables might measure up against the actual weather variations observed over 37 years of weather data. My contribution was confined to general observations on how power systems work, and in particular how operational and investment choices can or should be managed in a market economy.

 

This was the subject of a previous post, but readers are recommended to refer not to my earlier comments but to the report itself and to the policy briefing. Links are given at the foot of this post.

 

The results were interesting and to some extent surprising. The work indicates a very large scale of storage requirement, driven primarily not by seasonal but by inter-annual variations – runs of years when wind may be below average, and a host of other interesting findings and questions. I was asked just to comment on what I saw as the core economic and financial implications regarding large scale storage.

 

Economics in his context is clearly about securing the right combinations of generation and storage, the principles to guide our decisions, and the mechanics of getting where we want to be. The objective is to find market or other mechanisms for the outcomes we want, ie getting to low or zero carbon at an affordable cost compatible with an acceptable level of reliability and energy security. It follows that this has to be much more than just a theoretical optimisation, but has to cover national policies, institutions, coordination, markets, regulation and infrastructure?

 

There are several particularly important general lessons from the report that have general economic and policy implications:

 

1.     First is the potentially huge scale of storage. With both scale and major economies of scale, we have typical infrastructure characteristics, that need to be financed as cheaply as possible. 

 

2.     Second, interactions between storage and generation choices and multiple other factors: including the demand side. The report illustrates just how complex this is.

 

3.     Third, conversion capacity, for moving energy in and out of storage, will matter and has perhaps hitherto been largely overlooked. 

 

4.     Fourth is the whole issue of policy and planning for reliability of supply. Traditionally this was mostly about adequate margins of generation capacity required over peak demands – so-called needle peaks. But the new world demands a quite different understanding of reliability, when we are talking about, for example, wind drought. The issue then is of kWh energy rather than kW capacity – a major distinction.

 

So the report raises some very serious questions. We can treat each of the above in turn.

 

First, it is clear that the storage need has all the characteristics that we associate with large scale infrastructure. This includes possible or probable incidence of natural monopoly, certainly substantial investment costs, long lived assets that are highly use specific, and a financial necessity for a cost of capital as low as possible. For private capital that would mean a high level of reassurance over future revenue streams and the future market and regulatory environment.

 

Second is the issue of the very complex choices, and their coordination, in systems that rely on storage. It’s important to recognise that there are two distinct timescales here. One is operational - operating the system as efficiently and economically as possible with whatever is the current mix of assets. The second is about necessary investment -  creating the best mix of assets for the future. In a perfect market efficient solutions on both timescales might be expected to result from market prices.  But in the new low carbon world that looks increasingly like a pipe dream.

 

The conventional view of power sector markets was that the price signals  in a competitive market derived from the immediate needs for the efficient operation of mainly generation assets, replicating what might happen in a fully optimised system such as the merit order. It also had to provide an incentive for adequate capacity.  Various extra mechanisms have often been added that attempt to put a valuation on reliable supply; this is sometimes referred to as value of lost load or VOLL.  In principle it was hoped that all this collectively would  incentivise the right mix of assets, generation, networks and storage for efficient and affordable future systems. In practice the most that can be said is that experience has been mixed.

 

So what is new. Traditional spot markets were developed to deal with gas and coal powered generators, and to replicate a merit order based on SRMC. They were also largely designed by the employees of those generators They do not translate or adapt easily to low carbon technologies with more complex, probabilistic, intermittency and operating constraints.​ Storage adds new dimensions, by being intrinsically multi-period, requiring in addition that attention is paid to conversion capacities, and the very different nature of the reliability issue.

 

The simple metrics of short run cost that sit behind conventional market mechanisms do not capture the information or the complexity required. Investment choices, on the four-way balances between generation, transmission, storage, and conversion capacity, pose further questions, implying a need for coordination. Discussion at the Royal Society brought out some additional questions on the subject of conversion capacities, my third point.

 

My fourth point may well be the most important public policy question for the future – the security and reliability of electricity supply. We all know that governments cannot stand aside from issues of energy security, and electricity security in particular, however much they might wish to. However this is another dimension where the economic and policy calculus has to change radically, with some very different metrics.

 

Historically supply reliability in the UK has been about generating capacity – kW, and occasional insufficiency of kW to meet needle peaks. But future crises, if they relate to sustained weather related shortages, will be about kWh rather than kW.  Threats of months of energy rationing require an entirely different way of thinking about reliability. Possibly once in a generation events, like the 1970s 3-day week, a covid crisis or curtailed gas supplies, may mean looking at not just energy supply planning but also the overall energy resilience of the economy. 

 

Answering all these questions means great attention to the institutional and market structures of the sector. We have to decide who should own and operate large scale storage, on public or private ownership, integration with grid operation, guarantees for private capital, who should make the decisions on energy security and reliability, and so on.  

 

All these issues are closely inter-related, and the report offers an indication of where we might find the answers. These must rest on some combination of the following:

 

·      Novel market mechanisms and incentives to reward provision of storage capacity and conversion capacity.

 

·      elements of long-term contractual assurance for infrastructure providers,  eg a regulated asset base approach, or government guarantees.

 

·      Centrally driven coordination of investment plans. Quite common internationally (eg France’s EDF and Germany’s Energiewende).​

 

 

·      Enhanced role for the National Grid 

 

·      The creation of a ‘central buyer’, to procure capacity, but also to buy power from generators and sell to retail suppliers and large consumers.

 

·      Close cooperation between energy companies who implicitly assume collective responsibility for reliability  (the US ‘power pool’ model) 

 

In summary the economics for me is about:

 

·      balancing the roles of markets, thus retaining a role for competition, and central coordination

·      financing storage as essential infrastructure, and 

·      re-evaluating the policy approach to planning for reliable future systems

 

Possibly the most important observation of all, though, is that all these things take time and the task is urgent. That means starting to address these issues now.

 

 

Large-scale electricity storage report

https://royalsociety.org/-/media/policy/projects/large-scale-electricity-storage/Large-scale-electricity-storage-report.pdf

 

Large-scale electricity storage policy briefing

https://royalsociety.org/-/media/policy/projects/large-scale-electricity-storage/Large-scale-electricity-storage-policy-briefing.pdf

ELECTRICITY, STORAGE, RENEWABLES AND NUCLEAR

                   

Sir Christopher Llewellyn Smith presented an important paper on energy storage to the 2022 Oxford Energy Day, of vital relevance to the UK’s net zero ambitions. The methods and findings also have implications for, and should trigger similar analysis in, many other countries planning to rely on weather dependent forms of low carbon generation. The basic question is how best to combine the storage of surplus output from low carbon sources (nuclear or renewable) when output is high and consumer demand is low, with the need to draw down when demand is high and output low. 

 

Drawing on material prepared for a forthcoming report to the Royal Society, and previously also presented to BEIS[1], he outlined both the complexity of the choices that lie ahead and the information, assumptions and methods necessary to resolve them. In principle the storage issue is not confined to renewables, but applies to any system with less flexible generation, eg baseload nuclear, if output is not immediately controllable to exactly match load. 

 

A precondition for understanding the economics of storage is to appreciate the significance of both the frequency of the charge/discharge cycle and the scale involved. It’s often widely assumed by commentators that solutions are simply a matter of advancing battery technology, thus reducing the cost per kWh stored of battery capacity, together with more pumped hydro storage facilities. Batteries, plus pumped hydro and a few other technologies for short term storage at similar cost, together with measures to persuade consumers to spread their loads, are likely to be sufficient to managing short term balancing and the average within the day mismatches between consumer demand and variability in renewable supply.

 

But these are not not nearly adequate for a renewables based system of the nature currently envisaged for the UK. One reason is the frequency or infrequency of the charging/ energy release cycles. It is relatively easy to justify £ 75-100 per kWh of storage capacity for a battery[2], or a similar capital investment in pumped storage[3], when there is a daily or more frequent charging cycle and the fixed cost of the capital investment is therefore spread over up to 365 days a year. This is not the case for seasonal storage, or, for provision against extreme weather events. With an annual or less frequent cycles for a single charge and discharge, such a high capital cost is unaffordable. 

 

The other factor is scale. The scale of summer/winter compared to daily imbalances is an order of magnitude greater, up to 2000 times greater than daily imbalances, although for the UK this can be substantially reduced with the right mix of wind (winter) and solar (summer) renewables.[4]  The bigger issue is weather variability. This goes well beyond daily volatility and including both “wind droughts” that can last a couple of weeks and very substantial multi-year variations.

 

This scale necessitates much lower capital cost storage solutions, even if the “round trip” energy conversions are less energy efficient than batteries. On current knowledge this implies some form of chemical, thermal or large scale compressed air storage (ACAES).  “Green” hydrogen produced by electrolysis is currently seen as the leading option, and the working hypothesis in the study for the Royal Society. 

 

Renewables generation in the UK is currently based mainly around wind and solar, and their weather dependent nature largely defines storage requirements.  Most significant are “extreme” weather events, such as an extended “wind drought” when the wind is not blowing anywhere in Northern Europe, and big variations driven by the North Atlantic Oscillation in annual renewables output – years with less sun or less wind. 

This highlights the importance of meteorological data. Substantial variations in annual output, and sustained deviations from average, mean that looking at just a few years of data does not reveal the scale of the problem. Llewellyn Smith uses “middle of the road” projections for consumer load, and “real weather” meteorological data over 37 years for his assessments, though expert meteorological opinion is that even this may not be enough to capture extreme events. In itself this is an important observation and is compounded by uncertainties over the future impact of climate change on UK weather.[5]  

Importance of the right mix of renewables

 

A first, and surprising, result is that, for the UK, and at least with projections of current load patterns, the need for storage is dominated by weather volatility not (as often asserted) by seasonality per se. In other words what matters is extreme weather or unusual weather patterns, eg two or three weeks of no wind or whole years with poor renewables output.

Typical or “average” seasonal storage requirements could actually be largely managed by having the right mix of wind and solar, with an 80/20 wind solar[6] split as one feasible option on the basis of the particular assumptions in the study.

 

However one of the findings of the study is that even the seasonal imbalances between summer and winter can vary substantially from year to year, reinforcing both the need for much more concentration on weather volatility, and the conclusions on the need for substantial long term storage provision.

 

Exactly how much storage is required will also be an economic choice based inter alia on the relative costs of storage and renewables capacity, and on conversion capital costs and efficiencies, but initial indications suggest numbers in the range 130- 200 TWh, serviced by 80-120 GW of electrolysers. The TWh of energy storage is very substantially higher than simply seasonal balancing needs, and represents over half total current annual consumption, while the electrolyser capacity in GW comfortably exceeds current peak demand. 

 

The result demonstrates the system importance of managing the mix of weather dependent renewables. Bringing baseload nuclear power and fossil generation with carbon capture into the choice of technologies also offers further options, but at least for a system with substantial renewables content, the analysis has essentially similar characteristics with respect to storage investment choices.

 

Most analysis has ignored capacity required for both input to, and extraction from, storage.

 

In the past reliability provision has been dominated by the need to meet “needle peaks”, to have sufficient kW capacity to meet extreme conditions perhaps experienced in only one half-hour of the year, with adequate kWh of energy reserve provided by stored coal, oil or gas. In the future reliability will depend much more on use of a kWh energy reserve without use of fossil fuel.

 

An obvious but hitherto mostly neglected element in the calculation is the capital investment in the energy conversion capacity required for putting kWh of energy into storage and taking it out for final use. Both require significant high capital cost capacity – electrolysis for the production of hydrogen as input to store (when renewables output exceeds demand), and then use of that hydrogen to generate useful energy, as electricity or heat, when demand is high. Both these types of conversion capacity will also have to operate at relatively low load factors, and the scale of electrolysis capacity will likely need to match that of current generation capacity. The loss of energy in this “round trip” – 41% efficiency for hydrogen - is often discussed, but not the amount or cost of capacity required to charge or discharge from store. This should be sufficient capacity to match either surpluses or shortfalls in renewables output, but there will be a trade-off between the extra costs implied by “wasting” or spilling renewables  output, the size of storage requirement, and spending more on electrolysis capacity. Identifying this gap in the analysis is another important result from the Llewelyn Smith analysis.

 

Policy Implications

 

There are also further general policy conclusions to be drawn from this work. 

 

The first is that there is a clear need for whole system coordination, over and above what can be delivered by markets alone. There is no visible mechanism by which uncoordinated responses to market signals can be guaranteed to provide a credible approximation to the right seasonal balance of renewables, notably wind and solar. Nor is this deliverable through collaboration between localised, decentralised systems. Similar considerations apply to getting the right amount of conversion capacity to ensure an economic and reliable infrastructure for storage – including both the stores themselves and the conversion capacity for inputs to store, electrolysis, and outputs as eventual use of the stored energy. This coordination is essential both at the investment stage and in system operation. 

 

A related policy conclusion is that the fundamental decisions on power sector investment and infrastructure need to be closely coordinated with decisions for the heat sector. Reliance on heat pumps for example will substantially increase the seasonal imbalances and introduce weather related volatility on the demand as well as on the supply side. 

 

A third is that we need to re-examine and discuss the treatment of reliability and risk in power sector policy and planning. A disturbing message from the meteorological data is that we do need to consider the possibility of very occasional crises, even if perhaps only one every few decades, when there is an extreme and sustained shortfall in energy provision. Such crises are of course not confined to renewables systems. The UK experienced the 3-day week of the 1970s, induced by industrial unrest, and the petrol rationing of the 1956 Suez crisis, and could experience, for example, type fault issues with nuclear power. The issue is how we plan against extreme events. The answer is not necessarily excessive and unaffordable investment in spare capacity, but to accept that from time to time we will have to face major crises which are disruptive but can be managed without societal collapse. The recent pandemic is just one such example.

 

What this might imply for managing some future energy crisis might be deduced from the 3-day week[7]. A temporary shutdown of energy intensive industries, for example, might also be interpreted as the realisation that much of our “store” of energy can in fact be more cheaply held in the form of stocks of the energy-intensive products themselves. There are in reality many ways of managing energy and many other risks. What is required is identification of what the risks are and the development of good coping strategies.

 

Perhaps a final observation Is that we cannot assume historical weather patterns, even over many decades, are not necessarily a perfect guide to what weather we might experience as climate change has an increasing impact on weather patterns, introducing additional uncertainty and additional risks. So climate change adds further risks even to the measures that need to be taken in mitigation.

 

Expect more discussion of these issues as they increasingly impact on our strategic choices. 

 

 

 

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[1] The main conclusions (subsequently refined) were presented in April 2021 www.era.ac.uk/Medium-Duration-Energy-Storage and were communicated to BEIS in May 2021.

[2] A credible target given the pace of current advances in battery technology. Peter Bruce’s assessment of battery costs at the Energy Day suggested an estimate of this order.

[3] Dinorwic pumped hydro in North Wales stores about 8 GWh output of energy. It cost c £425 mn in 1990, or about £ 100 per kWh in 2022 money. Current lithium battery costs have recently fallen to this level and can be expected to fall a little further, perhaps to around £ 75 per kWh. 

[4] We can define a hypothetical storage need for “flattening” a load curve as the storage needed assuming 100% conversion efficiency, 100 % load factor of generation output which exactly equals total consumption. On this basis daily load curve flattening, historically, needs a mere 80 GWh, about 10 Dinorwics.  But a notional flattening of the annual curve, calculated from monthly seasonal pattern, needs about 17,000 GWh or about 2000 Dinorwics. In fact as the analysis shows, this need not depend entirely on storage and, for current seasonal patterns, could be largely managed by seasonal balancing (wind/solar mix) of renewable  capacity. Current UK annual consumption is of the order of 300,000 GWh. (Seasonal balancing needs can be checked from data at statista or other data sources)

[5] The Met Office suggest this does not provide a sufficient sample of “rare” weather events, indicating the need for contingency provision.

[6] Readers may be surprised that a smaller solar percentage actually requires storage of winter output for use in summer.

[7] It is interesting that at least one commentator has suggested that Germany, given the risks of its high dependence on gas, might usefully learn from UK experience in 1973/74 measures.

ENERGY STORAGE. FINDING THE SILVER BULLET

Energy storage is now widely recognised as a necessary component in most options for achieving a low carbon future. For most of our history, energy storage has taken the form of physical stocks of fossil fuel, to be drawn on as and when required. Matching supply and demand in real time has therefore been comparatively simple. Even in the complex world of large power systems, generation can be turned up or down with comparative ease.

That world is changing. Renewable resources (mostly) provide energy according to their own timetable and the dictates of weather and season, most obviously so for the best developed resources of solar and wind power. Nuclear power output can be used to follow load, at a cost, but is still relatively inflexible. Matching these outputs to highly variable consumer demand, for a variety of energy services from heat to transport, as well as appliances and processes of all kinds, is going to be more and more challenging. This implies the fundamental importance of energy storage.

The key technical and economic requirements will in different applications include minimising weight or volume (car batteries), round trip energy efficiency (minimising losses in conversion processes to and from storage), sufficient scale (for large power system applications), low capital cost per kW (unit of power output), and low capital cost per kWh (unit of energy stored). The application determines what is most feasible and economic in each case, and hence also both the choice of existing technologies and the priorities in looking for new approaches.

It’s often widely assumed by commentators that the great advances in battery technology mean that we are well on the way to solving all these problems. However that is far from being the case. Lithium- ion batteries are probably reaching their inherent natural technical limits, and although it may be possible to force down production costs further, they still represent a very high capital cost. As a result cost, as well as any scalability or resource limitations, are likely to inhibit their use other than in premium and high value applications, even though these extend to some high volume uses such as electric vehicles (EVs) and a few specific power system applications.  Currently foreseen battery technology scores well on efficiency and reasonably well on cost per kW, but not on capital cost per kWh.

We need and are going to need a number of very different types of storage, and the requirements differ widely across the spectrum of energy services and other requirements. Here are a few of the key issues and questions.

In practice the really critical distinction is between situations amenable to storage solutions that operate on the basis of a daily cycle or similar, and those that have to meet annual or seasonal cycles.  For the former, high capital costs can be acceptable but conversion efficiencies will matter more. For the latter, the reverse is the case. Low capital costs are essential and conversion efficiency less important.

The Dinorwic pumped storage scheme in North Wales illustrates the issue of scale and cost very well.  Dinorwig, the main storage facility accessed by National Grid in the UK, stores the equivalent of about 9 GWh of energy.  Construction is estimated to have cost c £ 500 million and involved shifting 10 million tonnes of rock.  It provides a significant contribution to managing daily load fluctuations, but is still relatively small in relation to the overall fluctuations in the daily load curve. In practice Dinorwig is sometimes used for the provision of ancillary services such as frequency control, rather than in the more obvious role of storing energy against a daily peak demand. Operating on a daily cycle, the all-in cost of storage is of the order of only a few pence per kWh, allowing the facility to make a valuable contribution to the efficiency of the power system.

The amount of storage necessary to flatten the typical current January daily load curve is of the order of 80 GWh, or about 9 Dinorwigs, in principle still a credible level of investment. However to cope with even the UK’s current annual seasonal variations in electricity consumption, the storage need would rise to about 17000 GWh, or nearly 2000 Dinorwigs. On conservative estimates of the need if UK space heating loads were to be met through electricity (even using heat pumps rather than resistive heating) the seasonal storage requirement could be up to three times higher, or 6000 Dinorwigs.

Recovery of the very high capital costs of storage, through revenue or compensating benefits, on the basis of a once a year store/ draw down cycle, is clearly impossible. The silver bullet of cheap seasonal storage has to come through a technology with extremely low capital costs per unit of storage capacity measured in kWh. The prima facie front runners for high volume seasonal storage are chemical or heat based solutions, including hydrogen/ ammonia, synthetic fuels, and bulk heat or phase change methods.

The nature of heat and chemical storage solutions means that seasonal and indeed all storage choices for the power sector can only be properly evaluated by reference to the totality of the energy system. This is most evident for the two very substantial sectors of heating and transport, whose decarbonisation is an essential part of energy policy, since

·         widespread use of heat networks provides an easier means to tap into low cost seasonal heat storage than attempting to recover the stored energy as electricity to power heat pumps.

·         choices in the transport sector, eg between hydrogen and electric vehicles, have profound consequences for the management of electricity supply.

·         electric vehicles are themselves a potentially substantial source of relatively short term storage, as protection against any intermittency in renewables supply.

But this also emphasises the need for a coordinated approach that treats the energy system as an entity, aims to minimise costs and finds compatible paths forward across the very different elements of power, heat for buildings and transport. Current market structures fall a long way short of that requirement.  

GRID SCALE BATTERY TECHNOLOGY IS COMING. INTERESTING QUESTIONS FOR COMMERCIAL ADOPTERS AND SYSTEM OPERATORS.

Battery technology is becoming a hot topic for larger commercial consumers, and may soon become a viable option for domestic consumers too. And National Grid is contracting for battery storage as a back-up resource. But how batteries are best deployed in today’s power networks is a complicated question. Today’s wholesale markets and tariff structures are very imperfect and may be quite dysfunctional in the world of fast moving technical change that includes communications and control in power networks. Consumers investing in batteries to make or save money are therefore advised to look carefully at the options, and the small print in tariffs and contracts. There are opportunities, particularly in exploiting anomalies, but wholesale markets and utility tariffs can change very quickly, and maintaining flexible options is likely to be the wisest strategy for business consumers.

What led to this comment was a request to talk on the subject of commercial opportunities at a recent energy management exhibition (EMEX) held in partnership with the Energy Managers Association. There is strong current interest among commercial consumers, such as supermarket chains, in the installation of banks of batteries. These can help to enhance security of supply, but this is not a primary motive for a significant investment outlay.

Batteries are now proving to be a valuable option for power systems, with several potentially useful functions. These can include spreading national or aggregate system loads over the day, providing emergency back-up and other ancillary services, and managing thermal and voltage constraints in local distribution networks. A two year trial of the largest grid-scale battery in Britain has proved it can potentially transform the energy grid and play a major role in the transition towards a low-carbon economy. The latest auction round for back-up capacity is reported to involve procurement of 500 megawatts of new storage projects.

The fact that batteries also have significant value at the lower voltage levels of local distribution networks, as well as in contributing to the management of aggregate demand and supply, is very relevant since it means that the battery owner may want or need to have a commercial relationship with both the National Grid and the local network operator. It also suggests that, in relation to local networks, there may be a premium on mobile batteries since load constraints on the network may occur in different locations at different times.

Some new loads, such as electric vehicles, are likely to further increase the need for batteries within the control of the system operators, again both at national or system wide levels and at key nodes within local networks. A good example is described in the Norwegian experience described in an earlier comment.

Will commercial scale batteries operate in front of or behind the meter?

From a commercial consumer perspective, the investment case for battery purchase and installation rests on three possible sources of revenue or cost saving, arbitrage in the wholesale market where there is regular opportunity to “buy cheap and sell dear”, responding to use of network tariffs that are strongly differentiated by time of day, and contracting directly with the network system operators.

Arbitraging wholesale markets.  The risk in relying on trading in wholesale markets is the volatility in prices from year to year. Wholesale prices are expected to be high this winter, in early 2017, but this expectation is critically dependent on capacity margins. Additional capacity or less than expected demand growth can dramatically reduce prices and the opportunities for arbitrage. In the medium term, it is increasingly likely that conventional wholesale market structures and assumptions will be overturned in progress to a low carbon economy, possibly reducing the importance of wholesale “spot” prices. Basing an investment on the ability to exploit arbitrage opportunities needs to take account not just of immediate market risk but also future structural change.

Exploiting distribution use of system (DUoS) tariffs. Some published network tariffs are highly differentiated by time of day, enabling consumers on these tariffs to make very large savings if they are able to move their usage away from peak loading on the local network, for example by using their own battery storage. In the case of supermarkets this may also be possible by using a store of “cold” to reduce their refrigeration load.

But the key factor here is that these structures are often extremely imperfect economic signals and are very crude devices to influence the shape of consumer loads. Exploiting anomalies in the tariff structure is ultimately a zero sum game. Ultimately the network operator is a utility that will be allowed to earn a regulated rate of return. Its costs are composed mainly of the fixed costs of the network, so the network utility will be forced either to recover more revenue from other customers, (highly unpopular and subject to regulatory intervention), or to rebalance the tariff to remove what may actually be a distorting incentive. Again this is a commercial risk if this is the prime motive for investment in batteries.

Contracting directly with the network operator. This is a novel development for network operators but, as shown in the recent auctions, it is a trend that is now under way. It raises the more general question of whether it is more effective to have the system operator managing batteries as facilities contracted from the battery owner, or to try to manage the system through complex tariff structures which try to second guess consumer behaviour. In the first case we might describe the battery as “in front of the meter”, and in the second case “behind the meter”.

A wise decision for the commercial consumer considering battery purchase, which of course can also provide a small amount of extra security, would be to make this investment as flexible as possible, to allow for direct contracting as well as managing its own demand. In dealing with local networks, there might also be a case for making the batteries trailer mounted, to allow further geographic mobility and to meet changing local network needs.