Why the UK needs an energy security rethink

London at night
Sebastian Blake
Sebastian Blake, Commercial Analyst, Open Energi

Blackout Britain is a headline which has become increasingly common over recent years. Many argue that decades of under investment in generation infrastructure has left the margin between demand and supply in the UK desperately short, raising the possibility of network outages at times of high power demand. Given the blame that would be landed at the Government’s feet were the lights to go out, energy security has been given top priority over the other facets of the energy trilemma; decarbonisation and affordability.

The Government’s solution to this was to devise the Capacity Market as a mechanism to encourage investment in new power plants, with yearly auctions for participants who can provide capacity over the winter peak. Crucially, auctions are held four years in advance of the capacity ‘go live’ date, to guarantee revenue and give investors the confidence they need to build new power stations.

There are, however, major flaws in the thinking behind such an approach. There is much evidence to suggest that the UK is in fact well supplied with power station capacity, that building more stations is unnecessary and that running the system more efficiently on tighter margins is a good thing. And by ensuring there is sufficient power plant capacity to meet the instance of highest demand in the year other potentially greater threats to security of supply are being ignored.

The graph below shows the frequency of the UK grid, which is the primary indicator of the system stability. The network is in balance when the frequency is hovering around the 50Hz mark, however any significant variation either side is a sign of a serious imbalance between generation and demand and could result in a potential shutdown of the network. This isn’t a distant threat: whole towns had to be shut off as an emergency measure in 2008 when grid frequency dropped to 48.8Hz.

Grid frequency graph

In this case, we can see what happed to the frequency when a large supply source – an interconnector between the UK and France – failed, leading to more power being drawn by consumers than was being supplied to the grid. To counteract the resulting frequency drop and avoid a system shut down, a series of automatic measures kicked into action, including turning up thermal power plants (coal and gas) and sending water reserves cascading through turbines of hydroelectric plants.

More recently on the 9th May 2016 there were 37 significant failures across 27 different coal and gas plants as well as the France interconnector; with each one disrupting frequency and testing the grid’s resilience. At one point in the day National Grid issued a warning that insufficient spare capacity would be available in an hour’s time. This is too short notice for a thermal plant to start up (which takes around four hours) so not something the Capacity Market would have helped with.

National’s Grid’s Head of Commercial Operation Cathy McClay has said managing the grid frequency is becoming an increasing headache for our island system. However, the technologies traditionally used to respond in these situations look increasingly unfit for the role. The best new candidate is demand side flexibility – in the form of batteries and demand side response – which offers numerous benefits.

 Energy storage and demand side response offer five core advantages over traditional solutions

  1. Speed of response: Demand side response and batteries can deliver their full power in under 1 second from receiving a request from the network. By comparison thermal plants and hydroelectric generators need around 10 seconds. As the interconnector example shows, this difference is crucial for avoiding a potential network shutdown and will be needed more and more due to continued reductions in system inertia.

 

  1. Decentralisation: Demand side response and batteries are distributed technologies meaning a required level of response can be made up from aggregating together many smaller sites. We have seen how relying on large centralised technologies (like the undersea link to France) poses increased risk to system stability as they represent significant single points of failure. Thermal power stations fail on a daily basis so individual plants cannot be relied upon for response; whereas with distributed technologies this risk is shared across many assets; if one fails the whole service is not compromised.

 

  1. No need for spinning reserve: Traditional providers are only able to achieve the 10 seconds or so when starting from an already running position, hence the generators must be operating at some partial output to provide the quick response. This impacts fuel efficiency by around 10-20%, greatly increasing costs and CO2

 

  1. Flexibility: The network can only absorb as much power as there is demand, so at times of low demand, National Grid must turn down clean and zero marginal cost power from renewable sources like wind to accommodate the thermal generators which must be kept running for frequency response. Demand side response and batteries overcome this problem.

 

  1. Low carbon: By maximising the use of demand side response and energy storage technologies, the UK will be able to achieve further growth in renewable generation; while reducing its reliance on interconnectors and its exposure to volatile gas prices.

 

The high capacity fossil fuel plants which have historically been used to respond to the demands of the grid are increasingly unfit for purpose in a modern electricity network, yet the Capacity Market fails to encourage the development or implementation of smarter, cleaner and decentralised solutions which would provide a more efficient means of addressing both our energy security and other elements of the trilemma.

Neglecting these alternative solutions via the Capacity Market will undermine exactly the thing Government is trying to advance: security of supply. National Grid should be applauded for its efforts to implement change through its Power Responsive campaign – designed to encourage demand side participation in the balancing markets – but many policy makers remain locked into the old paradigm of an archaic industry; no doubt weighed down by the stranglehold of well-established energy incumbency (better known as the Big Six).

For these parties, using distributed assets to balance the system still represents a significant departure from the orthodoxy of constructing and operating a few large centralised assets like Hinkley Point C, which will deliver 7% of all UK electricity when completed.

To achieve a real paradigm shift towards a secure, affordable and low carbon economy, we don’t even need to find new solutions. Distributed and demand side technologies are ready to deliver; we now need to change the supply-focused mind set of our policy makers and operators.

By Sebastian Blake, Commercial Analyst, Open Energi

Ever ready: will batteries power up in 2016?

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David Hill, Business Development Director, Open Energi

Open Energi tends to extol the virtues of Demand Side Response as a solution to the energy storage challenge.  It provides a no-build, sharing economy approach which is cheap, sustainable, scalable and secure.

By harnessing flexible demand and tapping into the thermal inertia of bitumen tanks or the pumped energy stored in a reservoir for example, we have created a distributed storage network able to provide flexible capacity to the grid in real-time without any impact on our customers.

But flexibility comes in many forms, and as the cost of energy storage systems tumble, it looks like 2016 might be the year when commercial batteries become a viable part of the UK’s electricity infrastructure, with recent analysis suggesting they could deliver 1.6GW of capacity by 2020, up from just 24MW today.

The price of energy storage systems is expected to fall sharply over the next three decades, with Bloomberg New Energy Finance predicting the average cost of residential energy storage systems will fall from $1,600 per KWh in 2015 to below $1,000 per KWh in 2020, and $260 per KWh in 2040.

As costs have fallen we have seen increasing interest from industrial and commercial customers keen to explore the benefits of installing batteries on-site and looking at systems capable of meeting 50%-100% of their peak demand – depending on their connection agreement (although it is worth noting an export licence is not a prerequisite).

In addition to providing security in the event of power outages, battery systems can help companies to reduce their demand during peak price periods, enabling them to seamlessly slash the astronomical costs – and forecasting difficulties – associated with Triads, and minimise their DUoS Red Band charges.

When they aren’t supporting peak price avoidance – which may be only 10% of the time – batteries can help to balance the grid – earning revenue for participating in National Grid’s frequency response markets. For example, discharging power to the system if the frequency drops below 50 Hertz and charging when the frequency rises above 50 Hertz.

National Grid’s new Enhanced Frequency Response market has been developed with battery systems in mind – requiring full response within 1 second – but isn’t expected to be up and running for a year or more.

In the meantime battery systems can generate significant revenues today via National Grid’s Dynamic Firm Frequency Response market, tendering alongside loads from companies like Sainsbury’s, United Utilities and Aggregate Industries, to help balance the grid, 24/7, 365 days a year.  And in the longer term the opportunity exists for companies to trade their batteries’ capacity in wholesale electricity markets.

With these saving and revenue opportunities in mind, we’re now at a point where battery systems can be installed behind-the-meter and deliver a ROI within 3-5 years for industrial and commercial sites. The ROI will be subject to certain factors, such as geographic location, connection size and of course the cost of the battery system itself, but these figures would have been unthinkable only a few years ago.

There are important technical factors to consider, including both the battery sizing in terms of its kW power rating and kWhr energy storage capacity, and also the underlying battery chemistry.  By taking into account the physical location of the battery along with models of different markets that it will operate in, it is possible to narrow down to the most appropriate technical parameters.  Another consideration is the gradual effect of wear and tear on the battery with continuous usage.  By analysing these effects it is possible to reduce some of the uncertainty around battery lifecycles (likely to be in the region of 10 years) and get better predictions of the likely revenue in each year of operation.

But whilst a payback of 5 years seems reasonable from an energy infrastructure perspective (where 15-20 years is more typical) for most companies used to a ROI within 2-3 years on energy projects it is not easy financing battery systems.

Some larger, capital rich companies may have the appetite and money to finance these projects themselves, but the majority of the companies we are talking to are keen to take these assets off balance sheet and finance installations via banks and other investors under third party ownership.

In these circumstances, managing the performance of battery systems – so that they meet their warranty and their lifecycle is maximised – whilst optimising their potential as a flexible resource able to cut energy costs, earn revenue and deliver a vital uninterruptible power supply  during outages will be key to their commercial success and scale of deployment.