Towards net zero: is battery storage leading the way?

As the UK decarbonises and real time balancing of the electricity system becomes more challenging, battery energy storage will play a crucial role in maintaining a stable system. The UK’s Electricity System Operator, National Grid ESO, has the ambition of operating a zero-carbon electricity system by 2025. This growing requirement for robust real time balancing of the system has been the dominant revenue driver for battery storage projects over the last few years, via Firm Frequency Response. As the ESO begins a journey of reform in UK frequency regulation via new services such as Dynamic Containment, and 2025 draws closer, we look back at how the system has changed and the impact that batteries have already had, through the lens of grid frequency. 

The UK’s electricity system has been rapidly decarbonising over the last few years: renewables accounted for 19.1% of generation in 2014. In 2020, this figure stood at 44.1%. As we move towards a zero-carbon grid, a higher proportion of electricity comes from renewables with no rotating mass, and this has an impact on how the system is operated – not just in dealing with GW swings in wind generation within a few hours, but in the delicate balance of supply and demand over a matter of seconds. 

The spinning turbines of traditional power generation give rise to system ‘inertia’: similar to a bike wheel that keeps turning when you stop pedalling, inertia is an important part of the stability of a power system. Grid frequency is then the needle showing the stability of that system; when all things are equal, it is 50Hz. When they are not, blackouts can occur – frequency plummeted to 48.8Hz on August 9th 2019, leading to nationwide power cuts. 

Here, we look in some detail at grid frequency since 2014: at the trends in frequency ‘events’ (when frequency spikes or dips in response to an outage), and in the way the system recovers. Because we have many more renewables now, system inertia has decreased. We see that year on year, grid frequency is becoming more volatile (see Figure 1), and events are becoming longer. However, the rate of change of frequency (RoCoF) is becoming less severe (Figure 2).  

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So why would RoCoF, a key indicator of system stability, be getting ‘less’ bad with decreasing inertia? One explanation for this is in the new technologies which have been coming onto our system in recent years. National Grid ESO, the UK’s Electricity System Operator, procure an array of services to balance supply and demand in real time. One of the most important of these is dynamic firm frequency response (FFR), in which a plant moderates its output to help balance the system in real time, given the system frequency. It has become dominated by batteries, which, when operated well, can respond reliably and nearly-instantaneously to frequency events – and crucially for net-zero, cleanly.  

Figure 3 shows the volumes of frequency response from different technology types. Since 2014, batteries have gone from providing no FFR volume to now providing virtually all FFR volumes. This, alongside frequency regulation volumes delivered by batteries via Enhanced Frequency Response (EFR) tenders, and more recently the Dynamic Containment (DC) auctions, mean the UK now has close to 1GW of low carbon, ultra-fast battery storage providing real time frequency regulation to balance the electricity system. 

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Looking at two comparable frequency events, one from summer 2017 and one from summer 2019, we can corroborate this theory. There were similar conditions on these days – a similar national demand (INDO), wind outturn, and a sudden power loss equivalent to around 2% of total demand (Table 1). The event in 2019 is after the evening peak, when national demand is decreasing, while the one in 2017 is during the evening ramp. Figure 4 shows the frequency trace for these two events, on a common time axis. 

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Despite the slightly smaller loss in generation causing the 2017 frequency event, it was more severe – with a larger RoCoF and reaching a lower frequency: 49.57 vs 49.70 Hz. The post-event response overshoots and subsequently the frequency remains high for a couple of minutes, whereas the 2019 event returns to a frequency close to 50Hz. While time of day considerations may be at play, it is interesting to consider the volumes of frequency response on the system during both of these periods: see Figure 5. The earlier event had around 30% more dynamic FFR volume. Logic then says the system should stabilize more quickly to a comparable loss, but the opposite is true. However, there is a marked shift in the makeup of that volume; batteries in both FFR and EFR provide significantly more of the stack in 2019.

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The fault recovery of the system appears much better in 2019, suggesting all of these batteries are really improving our response to unplanned plant outages. Returning to the bicycle analogy, it’s much easier to stop a bike from falling over if you catch it just as it starts to topple rather than just before it hits the ground. Batteries are so much faster as compared to the gas, pumped storage and hydro plants which dominated just a few years ago, and it means the system operator needs less volumes to provide the “same” service, so it’s more efficient. Batteries are also very happy performing these low utilisation services – we see very low levels of cell degradation in battery systems performing FFR over long periods of time, and it can be easily stacked with other services. 

All this is great news for net-zero. Leaps and strides in energy storage technology over the last few years, alongside the platforms which operate them, mean we can integrate far more intermittent renewable generation into our electricity mix – whilst ensuring the system remains robust and secure, crucial in our highly electrified society. As we build more wind and more solar, the importance of battery storage technologies in operating a decarbonised, digitalised, democratised and decentralised system will continue to grow. And, not just in frequency regulation but across the board of balancing requirements. 

Written By Grecia Monsalve

Dynamic Containment – a look into the crystal ball

After the excitement of January, which saw Day-ahead prices of £1,500/MWh and BM prices of £4,000/MWh, it feels strange to go back to writing about the comparatively mundane topic of Dynamic Containment (DC). However, its perhaps easy to forget that current prices of £17/MW/hr (resulting in battery revenues of £140+/kW/yr) are just as exceptional and are going to be vastly more important to the returns from battery systems this year than value obtained through trading -something almost no one was saying would be the case in 2021 a few years ago, when frequency response was old news.

The market is clearly in a phase of transition so the most important questions for investors and developers are: how long are these prices likely to last, and what will things look like afterwards?

What is Dynamic Containment?

Dynamic Containment is a new, fast-acting, dynamic post-fault frequency response service, the first of National Grid ESO’s (NGESO) new suite of frequency products. It is designed to stabilise grid frequency in case of large generation or consumption drop-outs, such as the interconnector trip on 28th Jan.

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Anyone who has been around the market for a while will know that trying to predict frequency response prices has bitten people badly in the past – we only need to look back to the crash of FFR rates in 2018 and the current rates observed in DC. However, improved transparency from NGESO and the dominance of lithium-ion storage now makes it a little easier to understand the market and predict where things are heading (famous last words…).

So, let’s look back at the recent past and the three main frequency response markets to understand the dynamics at play.

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As expected, supply and demand volumes are the driving factor for prices, illustrating a competitive and functioning market. Price discovery varies by market based on the frequency of procurement – the monthly dynamic FFR market takes much longer to settle at a new price than the daily DC market, which found its cap within a few days. DC is more valuable to NGESO than Dynamic FFR meaning those who can have left FFR to provide DC. In turn this has reduced the competitive pressure in the FFR market and raised prices for the monthly tenders. Essentially, the additional 500MW requirement which arrived with DC implementation has massively unbalanced the market in favour of providers.

This means that for forecasting the price forwards in the near term, the most significant elements are: NGESO’s requirement for frequency response volumes, the volumes of storage competing for these services, and the relative price caps NGESO sets for each service.

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On the demand side, luckily NGESO have published their forecast requirement for DC for the entirety of 2021, along with dynamic FFR requirement through to July 2021. Interestingly this shows a significantly higher requirement in the summer, which is perhaps to be expected given lower system inertia at this time.

Forecasting supply is a little more tricky. We know no other technology than storage looks able to meet the increased technical requirements of DC (namely speed and response) at scale and therefore we can use the pipeline of storage being developed over the next few years. Given the favourable investment environment and current sky-high DC prices, we can expect most of these to be bought forward to completion (this could see 500MW+ of storage being built this year!) and all of this capacity should be able to immediately enter the DC market. We expect a portion of dynamic FFR participants to continue to switch across to the higher value DC service. There are also some long-term FFR contracts coming to a close, along with EFR contracts doing the same towards the end of 2021.

Putting all of this together, and we start to get a picture of what things might look like in 2021.

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As we can see, this current market oversupply looks likely to remain in place until at least Q4 2021. It is actually incredibly hard to create scenarios that brings this point forward, given the higher requirement across summer and capacity not expected to enter the market until the autumn. This leads to the current high prices being maintained until late 2021 (as long as the price cap remains the same). When market saturation does occur, we would expect DC prices to quickly fall towards those available in the weekly and monthly FFR markets, and track these downwards from that point on at a rate similar to what has been observed historically.

Other things which could affect the value in 2021 (likely in a positive way) would be the introduction of high response DC and moving to EFA block procurement, albeit neither of these is certain to happen this year.

2022, by contrast, is a whole lot more complicated. The biggest factor at play here is the possible introduction of the remaining two new frequency response services: Dynamic Moderation and Dynamic Regulation. Initially scheduled to be introduced by March 2022, we now expect this point could be delayed towards the end of 2022. This then brings a few questions which right now are difficult to answer: will this see additional volume as with DC? What price will NGESO be willing to pay for these services? What assets will even end up being able to provide the high utilisation regulation service? If these products are introduced along the published timescales, we would expect to see a similar distruption of the market as seen with the introduction of DC with high prices in the short-term, albeit perhaps one resolved quicker as there will be more storage online to meet the requirement.

Other big questions are: what state do the 200MW of EFR batteries emerge from their contracts? Will they be able to jump immediately into providing these new services? And finally, will we see another bumper year of newly built batteries as we expect in 2021?

To keep things simple, if we assume the new products won’t be introduced for much or all of 2022 then as long as dynamic FFR volumes are maintained this should lead to similar market dynamics being at play in 2022. All in all, this could see 100MW or so swing the market significantly one way or the other, depending on whether the higher summer requirement sees the supply imbalance returning and prices moving towards the cap again.

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Frequency response prices have shown previously they have the potential to fall as low as £3/MW/hr in a saturated market, given the operational costs of providing frequency response are so low for batteries (a bit of efficiency losses and degradation). This time however arbitrage markets will provide significant opportunity cost – given the improved access to and consistent value demonstrated by trading and the Balancing Mechanism in particular. Batteries no longer have to accept rock bottom  revenues and become price makers in the frequency response market.

Beyond 2022, this optionality is going to be the main factor driving frequency response prices, as we expect storage capacity to start to significantly exceed the requirement for frequency response services. This will see prices starting to reflect the value available in these other markets, especially with EFA block (or even half-hourly) procurement. At this point, we would really hope to see price caps on frequency response prices removed or lifted to enable the market to function efficiently – otherwise next time prices of £1,000/MWh occur in the day-ahead expect to see much more volume exiting the market to chase this value. An example of a market functioning across multiple revenue streams can be found in Australia, where system operator AEMO manages procurement of both frequency response and energy, with price caps of $15,000. This sees prices vary significantly on a half-hourly (or even 5-minutely) basis in response to the requirements of the grid and value from arbitrage in the spot market.

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So, in summary: we can expect 2021 to be a very good year for storage assets capable of providing Dynamic Containment, but if anyone is telling you we will see the same in 2022 treat this with a huge pinch of salt. Be sure to engage system integrators and optimisers early to ensure assets are ready to go into DC on day 1. And ultimately, optimisers having the ability to seamlessly trade across 5+ potential markets whilst managing state of charge and warranty constraints will be vital to maximising battery returns.

Scarcity pricing in the Balancing Mechanism

The last couple of weeks saw some power stations make some bumper profits as cold weather drove scarcity pricing. The greatest profits were made by some large gas (CCGT) plant in the balancing mechanism on Friday 9th and Wednesday 13th January, earning up £4,000/MWh (around 100 times the normal cost of power), so what was it that enabled these plants to earn large revenues compared to other assets? 

The first thing to bear in mind is that the Balancing Mechanism (BM) is not a single market with a well-defined supply and demand but a marketplace for several system needs. The BM is used to correct supply demand imbalances that naturally occur (eg from demand forecasting errors) but crucially also to manage constraints, voltage, frequency, inertia, reserve (and more) in real time (sometimes augmenting specific tendered markets for these services). 

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If we examine the accepted actions by the System Operator (NGESO) on the afternoon Wednesday 13th after the event we can see this immediately given the large volume of both Bids and Offers accepted. If the only purpose was to correct the overall system imbalance it would be very inefficient to pay one plant £4000/MWh to turn up while turning others down at £0/MWh.

 Bids and Offers accepted 1700-1730 on Wednesday 13th. Source: LCP Enact.

These actions only start to make sense once we consider other requirements which the BM is used for, namely Reserve. Operating Reserve is needed to ensure sufficient backup from sudden impacts (like an interconnector tripping off or wind generation dropping off) and therefore GWs of back-up power is required to be available and able to respond in minutes. Reserve can be created by the System Operator through tenders ahead of time (STOR & Fast Reserve), bilateral contracts (SpinGen) and by creating headroom in the BM.

Headroom refers to difference between current output level and the Maximum Export Level (MEL) on thermal plant, the amount they can ramp up to and hold indefinitely. CCGTs take hours to start from zero ouput, but once operating above a Stable Export Level (SEL) they can change output in minutes and so contribute to Operating Reserve.

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A CCGT brought on to provide Headroom. Source BM Reports.

This is where we see the perverse incentive of being a large, slow moving beast sometimes emerges in the BM. Faster (traditionally smaller) plant like OCGTs, batteries and pumped storage can ramp up in a timescale of minutes (or faster) from a standing start which means they are naturally providing Reserve simply by offering volume into the BM. Whereas CCGTs must be turned on to SEL (and paid for this) to create Reserve.

Put yourself in the shoes of a Control Room engineer as the evening peak approaches: if you are looking at the resource available and think you might come up short clearly the best thing is to start up the slower plants in preparation for this. But if no incident does happen or the demand turns out lower than expected then the faster assets will likely not have been used during this period, whereas the CCGTs will have been renumerated heavily from the start-up instruction. 

This is what happened on Wednesday where each of four CCGTs were ramped up from zero to their Stable Export Limit (SEL), ie the least amount NGESO could procure, to create as much Headroom as possible. However, it turned out the system was long over the peak and with no incidents occurring meant many OCGTs received no instructions, despite offering much cheaper volume into the BM (it should be noted that size also plays a role here, the CCGTs offer much more volume). 

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 Accepted Offers from CCGTs to SEL 1700-1730 13/01/21. Source LCP Enact.

Offers from OCGTs not accepted 1700-1730 13/01/21. Source LCP Enact.

Offers from OCGTs not accepted 1700-1730 13/01/21. Source LCP Enact.

The problem is because in a utilisation payment only market the insurance value provided by fast responding assets isn’t valued if they aren’t called into action. NGESO are taking the right steps to remedy the issue by reintroducing STOR at Day Ahead (which allows providers to value in tight system conditions to their tenders) and investigating new methodologies like the BM Reserve Trial; both of which feature availability payments for those best able to provide Reserve. These are part of a wider package of Reserve reform which is fundamentally about the strategic shift to managing the system with predominantly duration limited resource, like batteries, instead of traditional notions of Headroom (and Footroom).

But this still doesn’t answer why the CCGTs were able to command such high prices. The answer is of course scarcity, cold days with little wind can create tight system conditions and we saw this reflected in the Day Ahead wholesale price at 1700-1800 (£1500/MWh on the N2EX). These CCGTs made the calculation they could earn more by not self-dispatching against the peak hour-long wholesale price and instead Grid would need to bring them online and pay high prices for an entire six hour run. It’s a gamble which doesn’t always pay off but did here, with a single unit at West Burton earning £3.78m from the BM that day compared to £0.53m if it had made the same run against wholesale.

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West Burton Unit 3 profits in the BM compared to wholesale. Source BM Reports.

The wholesale market and Balancing Mechanism are linked of course by the imbalance price and it is the SIP calculation formula which drives these trading decisions between the wholesale market and the BM. The SIP didn’t clear at high levels on Wednesday afternoon because ultimately there wasn’t a shortage of energy so the large costs of balancing on this day, shown below, are put down as Reserve costs and so instead pass through via BSUOS. Interestingly SIP did reach £990 earlier at 1pm that day when similar actions were being taken but the system was short (also on the 8th Jan when it cleared at £400/MWh). Whether this is the SIP calculation working well, or a sign it is broken, however is for another post.

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Balancing costs on week starting 11th Jan. Source NGESO.

UK Onshore Wind

Sunset for subsidies and a new day for batteries

Nearly all of the UK’s renewables generation was developed with the help of subsidies: feed-in-tariffs, the renewables obligation (RO) scheme and contract-for-difference auctions.

The gradual sunsetting of these incentives makes it a time of seismic change for the entire energy industry. That being said, it’s far from the apocalypse.

September’s energy auction, if anything, offered a glimpse of a future where advanced commercial and risk-mitigation solutions will become the best way to guard revenue streams, not public patronage.

The best place to observe this shift is in the case of onshore wind. These operators are vanguard for the end of subsidy, with schemes having been closed to new entrants for a few years. The first RO schemes for onshore windfarms will finish in 2027. It may not seem imminent, but the long-term investment required for renewables means that onshore operators should all be in advanced planning for future profitability.

 

The September CFD Auction turning point

The market was braced for big price movement well ahead of September’s contract-for-difference auction. It was still a surprise. Offshore wind went for under £40/MWH, 30% lower than the lower limit of 2017, and well under the government’s £49/MWH wholesale market price.

Far from a sign that onshore would never be able to compete with offshore peers, CfDs veering below wholesale prices only illustrated how close we have come to a level playing field – one where every operator needs every competitive advantage to succeed.

In the absence of subsidy, the challenge for onshore wind is maximising profits without offering too much of a discount on account of the unavoidable variability of its source.

 

Derisking the route to market

The two most straightforward routes to market for onshore wind are securing new long-term contracts outside of government auction or adopting an active next-day trading strategy, returning to the market every day.

An increasing number of corporations are looking to buy long-term power purchase agreements to secure a cleaner energy supply. This offers operators a welcome and predictable revenue stream, but at the cost of ‘paying’ the counterparty to take on the risk with discount prices.

The alternative is surrendering long-term security and deciding to ‘play the market’ with active day-ahead nomination. There are a number of options here: N2EX market, spot market or another balancing mechanisms. For those up to the challenge of a constantly changing supply and demand balance, the potential rewards are great. Unfortunately, so are the risks. Significant in-house expertise and attention is necessary to avoid one bad day wiping out a month’s worth of gains .

What both approaches share are returns which hinge on the risk of variability at the point of generation. This means any way of mitigating that risk will have a major impact on returns.

When bidding directly into the N2EX market, the operator must accept a variable day-ahead price for their forecasted wind generation, with any forecasting errors settled at a possibly lower, or even negative, price. While the mean day-ahead price will be higher than the mean price an energy supplier will be willing to offer in a PPA, the time-variance in the price leaves the operator at the mercy of wind forecasting errors – or simply untimely generation.

To make matters worse, high levels of forecasted national wind generation tend to lead to low prices.

A portfolio operator can mitigate forecasting risk by placing all wind farms under a single supply contract and nominating their aggregated volumes. This is because forecasting errors, while geographically correlated, will be lower on aggregate as positive and negative errors across the portfolio cancel out.

Managing day-ahead bidding, forecasting, and intra-day positions requires not only significant expertise but also robust IT systems. An energy optimisation platform with auto-bidding capabilities can do the heavy lifting cost-effectively, obviating the need to build this capability in-house.

To mitigate market risk, aggregated nominations are not enough, as geographical correlations in wind speed imply that times when wind speeds are forecasted to be high will also be times when N2EX prices will be low. It may not be possible to tame the wind, but what is possible is installing solutions that intelligently store energy and sell it at a time when prices are higher.

 

On-site batteries – to build or buy?

Wind operators who realise the value in installing (or upgrading) onsite batteries face yet another choice: install and manage the full operation of the new batteries, including the charge management, forecasting and market bidding, or – outsource it to a partner.

While most operators have highly technical teams, unquestionably the experts on the particular nuances of their own sites, a self-build strategy is still one where minor oversights or missed opportunities will rapidly erode ROI.

Take the deceptively simple task of choosing the right size of battery. Colocated batteries have the advantage of a shared grid connection point with wind generation on site, and a lower cost of installation due to easier access (compared to those out at sea). However, not every site will have the same amount of room before it hits its connection limit, or may have a wide range of forecasting error.

Making the most of each individual site, and avoiding wasted battery headroom or overflow energy spillage, requires careful battery selection.

Even with a wealth of site data, minor sizing errors will add up to significant loses in the long run. Lacking the size to conduct effective state of charge management, for example, significantly reduces the lifetime potential of each battery, and forces operators to either reinvest or seek external support after all.

Across larger portfolios, the benefits of a networked system of batteries is even greater. This is especially true for windfarms which have a greater potential for site-to-site variance than solar equivalents. With a connected system, the aggregation of risk and capacity means that the individual size (and cost) of each battery can be smaller, reducing overall cost. Larger portfolios allow for distributed risk, but also require more complicated systems to to apportion balancing between the available storage in the portfolio within the constraints of the battery systems’ warranties.

The most advanced management systems do more than simply manage a state of charge or capture overflowing electricity. Reducing variability and risk means also capturing every possible market access point, including accessing the ancillary services and capacity markets, and even the balancing market via a range of aggregators. Not only are these revenue streams decoupled from day-ahead market prices, diversifying market risk – they can more than double the value generated by the storage system.

Especially for larger portfolios, the potential ROI of an advanced management system far outweighs upfront costs. Forecasting day-ahead generation, managing charge levels and setting optimal nomination volumes for suppliers are all vital components of a long-term strategy to maximise return. Partnering with experts for both hardware and software is the most effective and rapid route to success.

In a year-long simulation using 2018 market prices, we found that a suitably sized battery storage system deployed on an on-shore wind farm running Open Energi’s DD2.0 optimisation software could annually generate £77.10 of value per kW of battery capacity (net of connection charges). The system helped buffer wind forecasting errors, reducing them by up to 75%, arbitrage day-ahead energy market price shape, and participate in ancillary services such as Firm Frequency Response.

At a portfolio level, the optimally sized batteries allowed the wind operator to take more risk with their PPA with day-ahead exposure, resulting in a 8% increase in portfolio turnover compared to a PPA with risk taken on by the supplier.

 

End to end optimisation

Wind operators don’t have the luxury of picking and choosing which areas they would most like to see revenue optimised. Every advantage is necessary to survive in a post-subsidy renewables energy market. A comprehensive solution, and an experienced partner to install and run it, offers the best and fastest route to future returns.

Open Energi is one of the UK’s longest standing providers of solutions to mitigate risk and improve market access for renewable operators. We have spent over a decade working to build solutions and platforms that help operators protect their revenue streams, ensure they begin delivering value fast. One of our most recently installations, at one of the UK’s largest battery sites, was taken from ‘contract to commission’ within a week.

The UK is rapidly approaching a time when renewables are competing directly – without government subsidy – through a mix of both long term and day-to-day trading through a range of markets. An onsite battery solution offers a commercially optimised route to success in the UK’s post-subsidy future with a high potential for capturing returns.

Charity cycle funds solar panels in Kenya. Thank you to all our sponsors!

London to Brighton-Ditchling Beacon

On the 27th September ten not-so-seasoned Open Energi cyclists gathered at London’s Clapham Common to tackle the 54-mile cycle route from London to Brighton in aid of Renewable World, a charity dedicated to bringing clean and sustainable sources of energy to power-poor communities.

We had an amazing day, and all arrived safely in Brighton with no major mishaps other than David Hill contriving to get a puncture 400 yards from the start, and Tom Saul delivering a circus-style dismount in front of an appreciative seaside crowd. Special mention goes to Clive Booth for completing the course (including the monstrous climb up to Ditchling Beacon) on a bike wholly unsuited to the purpose, the cycling equivalent of dragging a sack of rocks along behind him.

charity cycle

Most importantly though we would like to say a huge thank you to everyone who so generously supported our efforts. Collectively we raised over £3,700 which is paying for 20 X 24V (250W) solar panels for community owned solar microgrids for communities living on the shores of Lake Victoria, Kenya.

Access to renewable energy not only helps to drive improvements in the health, education and income of local people; it also reduces environmental damage.

‘Since I was connected to the bug, my life has changed. I want my wife to study at university, that is my dream.’ Charles, N’gore Village, Kenya

But there is a long way to go. Globally, almost 1 in 5 people do not have access to electricity; over 1 in 4 lack basic water services like taps and safe drinking water; and over 1 in 3 are without clean cooking facilities. Without access to energy, people remain trapped in a vicious circle of poverty.

Since 2007 Renewable World’s programmes have transformed the lives of over 35,000 people in Central America, East Africa, and South Asia, bringing life-changing renewable energy to communities in need.

To find out more about their fantastic work please visit their website.

ADE I&C Energy Conference

ADE logo

On the 30th October the Association for Decentralised Energy (ADE) will be hosting a practical conference designed to support developers, suppliers, industrial and commercial customers, funders and consultants in understanding industrial energy use in the future smart system.

Open Energi’s Commercial Director will join key market players and experts, discussing:

  • What will be the most lucrative markets in the future smart system for industrial energy?
  • How can large energy users increase their energy revenue and/or decrease their energy costs?
  • How can we make business energy policy more reflective of business needs?

Date: 30th October 2018

Location: Pinsent Masons, London,  EC2A 4ES

Speaker: David Hill, Commercial Director

Further information is available from the event website.

Energy Live Expo

Energy Live News

Energy Live Expo is taking place on October 31st. As always it will look at all the major energy issues of our time in particular the disruption taking place in the energy sector with new technologies, storage and of course policy changes as we enter our transition period of Brexit.

Open Energi will be speaking in the Innovation Hub, sharing our views on the future of energy tech and the opportunities for businesses to cut costs, create revenue and reduce carbon through energy optimisation and demand flexibility.

Date: 31st October 2018

Location: QEII Centre, Westminster, London

Speaker: David Hill, Commercial Director

Further information is available from the event website.

Share Your Energy Conference – 14.11.18

Share Your Energy

Share Your Energy is bringing together the most influential innovators of modern energy. Open Energi’s Head of Markets and Policy Sebastian Blake will join other leading energy tech companies to discuss the latest in flexibility, block chain, artificial intelligence and peer-to-peer energy markets.

Date: 14th November 2018

Location: Prague, Czechoslovakia

Speaker: Sebastian Blake, Head of Markets & Policy

Further information is available from the event website.

Future of Utilities: Smart Energy 2018 – 20/21.11.18

Future of Utilities: Smart Energy is set to bring together 300+ attendees for two days of collaboration discussing energy storage, supply and smart grid developments.

Featuring technology-driven content about how to make energy retail smarter, and systems more flexible, Smart Energy will showcase the experiences of a wider range of energy companies than ever before. 

Open Energi’s Commercial Director David Hill will join a panel session to explore the business case for storage and different approaches from across the value chain.

Date: 20th-21st November 2018

Panel: 14.35, 20th November

Location: The Tower Hotel, Guoman – London

Speaker: David Hill, Commercial Director

Further information is available from the event website.

How greater flexibility can help UK deliver 50% renewables by 2030

electricity pylons

The National Infrastructure Commission (NIC) recently published its first National Infrastructure Assessment (NIA), setting out a strategy for the UK’s economic infrastructure from 2020 to 2050. A key focus is decarbonising the UK’s energy supply and the report recommends 50% of generation is supplied by renewable power by 2030, with the UK’s electricity supply almost entirely zero-carbon – thanks to nuclear and renewables – by 2050. But how can we integrate this level of renewables cost-effectively, and what do we do when the sun doesn’t shine, and the wind doesn’t blow? Wendel Hortop, Commercial Analyst at Open Energi, explores the role of flexibility in enabling the UK’s transition to a zero-carbon energy system.

What would such high levels of renewables mean for the energy system?

The UK is on track to power 50% of our electricity supply with renewable generation by 2030 but this level of renewables creates some very specific challenges. Solar and wind, which would form most of new renewable capacity, are highly inflexible – energy is only generated when the sun is shining, or wind is blowing. Despite increasingly accurate forecasting, this inflexibility introduces short-term (balancing electricity supply and demand within a given half-hour) and long-term (what to do when wind and/or solar output is low for hours or days at a time) challenges, and reduces the level of inertia on the grid, resulting in much quicker changes in system frequency – which must be managed to ensure power keeps flowing.

Flexibility can help to address these impacts cost-effectively – reducing total system spending by between £1-7bn per year – and enable the UK to integrate renewable generation at the scale required by the NIC assessment.

Flexibility can deliver significant cost reductions in in a high renewable system

Source: Open Energi
Source: Aurora Energy Research

 What role does flexibility have to play?

The majority of system balancing occurs through the energy market in response to energy prices visible over different timescales, of which the last resort is the imbalance price. Energy generators and suppliers forecast their half-hourly energy usage and provide this to National Grid, who then take action to correct any differences between forecast and actual energy usage. Anyone out of balance in a way which harms the system pays a penalty, whilst the opposite is also true – putting yourself in imbalance to benefit the system gets rewarded. The imbalance price (or System Price) is not known until afterwards so predicting and reacting to it allows energy users to help the grid and be rewarded; increasingly trading teams at big suppliers are looking to their customers to help manage this.

Open Energi are already responding to the imbalance price by flexing loads through signals from suppliers, such as Ørsted’s Renewable Balancing Reserve. Increased renewable generation on the grid will increase the likelihood of system imbalances, and the incentive to respond.

Flexible loads can respond in real-time to predicted system prices

Flexible loads can respond in real-time
Source: Open Energi

The wholesale market doesn’t balance all supply and demand so National Grid look to the suite of services they procure to do the rest. For example, frequency response services fine tune the system balance and provide a ‘first line of defence’ after large generation outages.

Demand flexibility is already an established tool in helping to balance frequency on the grid via the Firm Frequency Response market. Inertia levels falling means faster frequency response is needed. Lithium-ion batteries are perfect for delivering this, whilst some forms of demand flexibility can also respond at the required speed. National Grid is developing a Faster Acting Frequency Response product which will allow loads capable of responding quickly enough to participate and will procure a mix of assets capable of tracking frequency (such as batteries) and those capable of delivering large shifts in demand almost instantaneously (such as large industrial processes).

Longer term shortfalls in generation introduce a new challenge for flexibility

The more significant challenge is in longer periods of low wind and solar generation. Increased interconnection with Europe will help but demand flexibility can again play a key role.

Frequency response has tended to focus on energy flexibility within a half-hour period, however many processes have inherent energy storage of hours or even days. Water pumps, heating and CHPs are all assets which can shift demand over long periods. The signals to do so come from the market – low renewable generation leads to increased wholesale energy prices, and vice versa. As wholesale energy prices can be known a day ahead, a load can be optimised in advance to increase consumption when prices are lowest, and reduce consumption when prices are high.

Many flexible processes have hours or even days of energy storage
 

Many flexible loads have hours or even days of storage
Source: Open Energi

Advances in storage technology will also assist with this longer duration requirement for flexibility. Technologies such as vanadium flow batteries can provide over 4 hours of energy storage and can help balance sustained periods of low or high renewable generation as well as providing short-term frequency response and price arbitrage.

Aggregation of assets such as these, diverse in both location and technology, will help to tackle longer periods by spreading the requirement for flexibility. Digitalised platforms that use artificial intelligence (AI), statistics and probability can schedule and manage asset behaviour to deliver the optimal amount of flexible capacity.

As we look to 2030, increased adoption of electric vehicles (EVs) will also come into play, either through smart charging or vehicle-to-grid (V2G) charging. In their latest Future Energy Scenarios report National Grid predict we could have over 10 million electric vehicles in 2030, and over 35 million in 2040 – a huge number of flexible, distributed assets.

Smart charging will allow EV charging to be modulated or staggered to avoid surges in consumption or shifted to times of day when demand is low, reducing the infrastructure required to support them. Aurora Energy Research estimate that smart charging can reduce the level of generating capacity required in 2050 by up to 22GW in a high renewables system. Meanwhile V2G charging introduces possibilities such as taking households off-grid during peak periods – Open Energi are part of the PowerLoop consortium exploring this and other potential V2G applications.

Smart charging significantly reduces the need for flexible generating capacity

Source: Aurora Energy Research
Source: Aurora Energy Research

Decarbonisation of heat will introduce new sources of flexibility

One common process with very high levels of inherent storage is heating; however the UK’s reliance on gas means potential flexibility which could be offered to the electricity system is currently limited. Looking forward the decarbonisation of heat therefore offers long-term opportunities, whether this comes through electrification or a transition to hydrogen and district heating.

Switching to heat pumps would introduce a large but flexible energy load into the system with significant storage potential. Coupled with smart meters and other advances in technology this could lead to a highly distributed source of flexibility for the grid, just as with the shift to electric vehicles.

Hydrogen powered heating – produced via electrolysis – is an energy-intensive but flexible process, which alongside district heating networks would likely lead to many more CHPs – which offer short and long term flexible capacity.

Technology will play an important role in delivering this flexibility

The NIA shows that flexibility has a key role to play in delivering or surpassing our carbon targets. As renewable generation increases significantly so will the need for flexibility. We already have many of the solutions we need – the real challenge is rolling these out at the required scale and speed.

This is where AI and cloud computing can come into their own. Aggregation of larger and larger portfolios of diverse loads will require the behaviour of each of these individual loads to be optimised and controlled in real-time in response to the requirements of the system. Meanwhile the move to smaller, distributed loads, including those on a domestic scale such as electric vehicles, will rely heavily on cloud computing with dispatch instructions delivered over the internet and loads communicating their behaviour with the platform and each other.

Ultimately these solutions can give rise to an autonomous, self-balancing grid which operates incredibly cheaply. Open Energi are leading this transition, connecting, aggregating and optimising distributed energy resources in real-time, to create a more sustainable energy future.