Towards net zero: is battery storage leading the way?

Volumes of Dynamic FFR by technology type since 2014. EFR and DC are provided by battery storage.

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 2021, which saw Day-ahead prices of £1,500/MWh and Balancing Mechanism (BM) prices of £4,000/MWh, it feels strange to write about the comparatively mundane topic of Dynamic Containment (DC). However, it’s 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.

Dynamic Containment response from Open Energi unit during IFA2 trip on 28th January 2021.

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 Firm Frequency Response (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.

Graph showing Frequency response prices from March 2020 to February 2021.

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.

Dynamic Containment requirement for 2021

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.

Graph showing the supply imbalance up to Dec 2021.

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.

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.

Graphs showing the energy supply type differences and pricing forecasts for 2021.

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.

Graph showing the Australian FCAS price fluctuations November 2019 to Jan 2020.

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.

Manual vs Automated Trading

In essence, optimising flexible assets in traded energy markets means trying to maximise (or minimise) the captured price for whatever energy can be sold (or bought) by the device in question: a gas power station, battery storage or just a single electric vehicle. In practice, it is often a highly complex exercise requiring processing and a combination of information from two distinct sources: the asset characteristics and market intel.

This cross-optimisation involves continuous calculation over different time horizons, as market opportunities (like Day Ahead auctions) and asset limits (such as ramp rates restrictions) must be planned against. A classic example would be a trader managing a gas power plant; assessing changing market conditions and working closely with plant operators to understand variable physical parameters, such as efficiency at different power outputs or the energy required to start up the generator.

This information must then be considered when selling energy into the power markets, and that involves a careful trade-off between physical and price considerations. For example, when low demand causes low prices overnight, plants must choose between shutting down in the evening then starting again in the morning or running through the night, selling power at a loss – whichever is the more economical.


Adapting to new technologies

However as storage, demand response and hydrogen production become the dominant tools for balancing the grid, this is also driving change in the methods for optimising assets. Novel technologies are being deployed at the megawatt or kilowatt level, not gigawatt, meaning many more assets will be involved in making up the required level of balancing capacity.

Each device has its own features and characteristics, such as power capacity or response time, as well as dynamically changing parameters impacting optimisation, eg state of charge (SoC) or energy recovery period. So it is clear when dealing with thousands of individual assets the complexity of the problem scales greatly.

Even for larger Front-of-the-Meter batteries, warranties are becoming increasingly complex to manage in real time; specifying rest periods or dynamically limiting depth of discharge, as opposed to simply warrantying a certain number of cycles per year. Also, many projects will be co-located with variable renewable power to exploit the benefits of a shared connection, effectively giving a dynamically varying export connection to factor into optimisation.


Pros and cons of automation

In this world, automation is fast becoming essential. Allowing the principles of continuous asset optimisation can be applied at a scale far below what would be economical for a human trader.

Open Energi has been trading fully algorithmically in the Day Ahead markets for over a year and has some key learnings.

On the face of it picking the highest and lowest hour in the day is simple (and fairly predictable). However, to maximise revenue you must also respond to more real time signals which occur within day (eg Triad), which alters your SoC from the planned schedule. This creates a problem when submitting bids in advance for the trading day before the current day has ended, as you do not yet know what SoC the battery will be at at the start of the trading day.

Automated fixes are able to easily correct for misalignments to get round this; however, doing so in the most economical fashion is harder. And the problem is exacerbated when dealing with more dynamically changing markets like the intraday continuous, which require thinking between different trading horizons.


Manual plus automated trading – a winning team

Overall, traders still have the upper hand on algorithms in areas like price formation, especially during extreme events like 4th March, and the best solutions will be ones that exploit the strengths of both. This is the principle of our solution Dynamic Demand 2.0 Trader, where full automation capabilities will perform the heavy lifting but oversight from Erova Energy’s 24hr trading desk provides the manual oversight and possibly intervention if greater opportunity is identified.

Ultimately, combining the strengths of power traders and algorithms provides the best optimisation. And ensuring each is capable of running independently provides the built-in resilience that proves its worth as COVID-19 pushes systems to their limits.


For a free consultation about automated trading, call +44 (0)20 3051 0600

Batteries in the Balancing Mechanism

The Balancing Mechanism (BM) is the primary flexibility market in the UK. In 2019 over 2TWh of flexibility was procured through the BM with a value worth over £800m. Batteries are only a recent (and small) participant – the vast majority of flexibility is provided by CCGTs and some through pumped storage such as Dinorwig.

Batteries have had over a year in this market and have steadily seen increases in activity, helped by the introduction of the Distributed Resources Desk, while upcoming Project TERRE could also help non-traditional providers receive dispatches. Hence, while batteries remain a niche player in the BM, compared to the dominant technologies of CCGT and pumped storage, there has been a steady increase in activity.

Figure 1 – Activity by batteries in the Balancing Mechanism has been increasing over the last year

Batteries in the BM – The Basics

The Balancing Mechanism is manually dispatched by the ESO Control Room – providers submit prices and volumes but only deliver (and are paid) when selected. Dispatch decisions are made based on a number of operational criteria, of which volume and price are just two. For example, only certain technologies are able to meet certain needs: thermal plant provide inertia but batteries don’t.

However, battery storage does have its own unique benefits as batteries can respond extremely quickly and accurately in either direction. This quality is being exploited by the Control Room with batteries delivering short bursts of power of mostly under 10 minutes duration (see fig 2). Traditional thermal providers cannot do this, given their ramp rate restrictions.

The most obvious difficulty batteries bring is that they are duration limited, whereas a gas power station could increase its power indefinitely. This means, once a battery has discharged completely, it cannot sell any more energy and so must recharge, either through trading or by waiting to be dispatched in the other direction. Batteries can be dispatched in either direction throughout the day – even if the system is long, batteries may be offered up, and vice versa, so leaving the battery empty (or full) would result in missed dispatches and lost revenue.

Figure 2 – A day of BM actions for a battery, light area showing availability and dark bands are dispatches. Most dispatches are under 10 minutes in duration.


State of charge – The limiting factor?

State of charge (SoC) is, therefore, a massively important consideration for both operators and National Grid alike. However, unlike the physical restrictions of thermal plant (such as minimum output), SoC is not captured in the BM, given it is a novel issue. We can infer when SoC has drifted significantly, though, as batteries adjust their available power (MEL and MIL) to represent 15 minutes of storage. This means that when less than 15 minutes output is available in one direction, the system can only be dispatched at this reduced level.

For a two-hour system this only has a small impact – state of charge can drift significantly in either direction before this limit is hit. However, for a one-hour system the impact is much more significant, as the battery could potentially be offering up reduced availability 50% of the time.

Overall, taking a much more active role in managing SoC is necessary to maximise benefit, especially for more limited duration batteries.


Being Active

Market optimisation of batteries within the BM takes two forms: integration with other trading strategies, and through much more dynamic provision of bid and offer price. Both of these offer solutions to more actively managing SoC to reduce time spent offering reduced availability.


The most obvious route to managing SoC during the course of the day is through the intraday markets. If one or more offers in a row start to deplete SoC, energy can be bought on the intraday market to recharge the system. However, doing so may not always be the optimal solution – eg if the price is too high, or perhaps it is likely a bid will arrive soon anyway.

An advanced optimisation and forecasting solution combining manual and automated inputs is needed to effectively manage SoC through trading; system warranty is a constant consideration and confidence will be needed that any actions will increase profitability later in time.

For the example below, purchasing just 30 minutes of energy at the time shown would increase total daily returns by 13%.

Figure 3  – A day of BM actions for a battery, with energy purchased through intraday markets around 9am (green), and corresponding increase in availability and dispatches shown in grey



Although operators have no control over whether their assets are dispatched in the BM, they can influence the likelihood of being dispatched in either direction by adjusting their posted prices, or by providing stepped bids and offers.

Increasing bid price in response to low SoC could be provided to increase the chance of dispatch, in order to then capture higher revenues across the whole day. Meanwhile, stepped bids and offers provide the Control Room with two or more prices, which can be paid to access different levels of power output.

However, this route still has a limitation in being dependent upon being dispatched, even if the probability of being so can be influenced.



The BM has long been talked about as the holy grail for battery operation but there is still a lot of uncertainty over when (and indeed whether) that point will be reached as system balancing transitions from CCGTs (with infinite duration headroom and footroom) to fixed duration energy storage.

However, recent activity has provided good signs for batteries to be the principle candidate to take over from CCGTs as the UK moves towards net zero, and we expect to see further design aspects of the BM to be updated in favour of storage assets, to enable NG ESO to meet its target of zero carbon operation by 2025.

Meanwhile, value from the BM continues to increase and challenge frequency response revenues – Open Energi and Erova Energy will be launching our Balancing Mechanism offering in the coming months, so watch this space!


For a free consultation about trading in the Balancing Mechanism, call +44 (0)20 3051 0600

Solar plus storage – The benefits of co-location

The UK will need 30GW of storage to meet our climate goals, according to Imperial College. That’s 10 times the current capacity. There are many questions this raises, such as ‘what is the appropriate technology mix?’, but if we consider the form predominantly being developed now (lithium-ion batteries of under or around two hours duration), one of the main questions is where best to situate this?

So far the vast majority of volume has been deployed as front-of-the-meter installations – a standalone site with a dedicated connection for the battery alone. However, given that connections can be costly or administratively difficult to obtain, a more cost-effective solution would be co-location.

In this blog we will dig into some of the advantages of co-location of batteries with solar farms (PV installations with a dedicated connection). We will leave the current policy/regulatory framework to the side and focus on the fundamental benefits.


The case for co-location

When new generation connects to the grid, it has to pay for the new copper in the ground. This isn’t cheap. For a battery (short duration, lithium-ion) the connection typically represents 10-20% of the total capital expenditure – and can be much higher, depending on the conditions of the local network (eg if you are unlucky enough to be the marginal connection requiring a sub-station to be upgraded).

If the battery was able to share an existing connection with a solar farm of the same size, it could save the 10-20% of upfront cost; it would still need to buy an import connection, which the solar farm doesn’t need, to ensure the battery can draw from the grid to charge, but the economy would be significant.

In the UK, solar PV (without tracking) has an average capacity factor of 10-15%. This means that for the vast majority of the time the connection is an expensive sunk cost, lying there unused. By sharing it with storage, the return on investment from the connection increases several times over.


Why solar and storage are perfect bedfellows

Sharing one connection becomes a problem when both energy sources are producing at the same time. Export from one resource will constrain the ability of the other to export. With solar and battery storage, we find that this is rarely the case; ie both assets are very seldom trying to use the connection to export at the same time [see fig 1].

This is due to the price cannibalisation of renewables – where prices are lowered at times of high renewable generation because they produce at zero marginal cost, and so will sell power at any price above zero. There is sufficient solar power in the UK (>12GW) that during the middle of the day market prices will drop lower.

If we are performing price arbitrage with the battery, it is obvious that we would not be looking to discharge at these times when prices are low. We want the highest prices – usually over the evening peak. In fact, we have found that when optimising the battery against Day Ahead prices, a conflict occurs with the solar generation less than 1% of the time.

Figure 1: Generally, the battery looks to discharge at times of high prices which does not align with solar output

What this means is that we can effectively trade the two assets separately from each other, rather than as one. This has great benefits because solar predictions are best made at portfolio level, taking advantage of geographical dispersion to neutralise stochastic cloud impacts on production. Therefore, the solar can be traded as a portfolio, while battery activity can be scheduled separately.

This also highlights one major advantage of pairing batteries with solar rather than wind. Solar has very high diurnal periodicity, so we can guarantee there would be no production over the most lucrative peak time (4-7pm, especially in winter). The same cannot be said for wind; so if it a wind farm was generating during this peak period there could be large entailed opportunity cost for the battery.

Given that the battery is the more controllable resource, and solar produces at zero cost, the battery should accommodate the solar generation and plan activity around it.


The need for advanced optimisation

Pairing solar with batteries, then, looks like an obvious and straightforward win. However, there is more nuance.

While Day Ahead prices will rarely incentivise discharging the battery in the middle of the day, there are often later market opportunities that do; for example, if a large generator trips off the network to create a shortage. The most advanced battery trading strategies will cycle far more than once per day by looking to optimise at each time horizon, to stack value across the day.

Given that cloud cover could have a strong impact on PV output, there will still be many instances where a solar farm has the connection unutilised in the middle of the day [fig 2].

Figure 2 – Clouds drive large short term volatility in production

To take advantage of this we need reliable, real time monitoring of the solar farm (we can only dispatch the battery and make use of the connection if we can be certain the solar PV isn’t) and dynamic responsive controls to ensure solar output is tracked closely (to prevent overloading the connection point).

Dynamic Demand 2.0 Trader is powered by our fully automated platform, needed to support this level of sophistication. Control logic is held both locally on the battery, to ensure responsiveness to changing site conditions, and centrally in the cloud, enabling responsiveness to live price opportunities provided by Erova Energy’s advanced market insight.

With this level of automated control and trading insight, pairing solar with storage represents a cost-effective solution for storage location and a potentially lucrative way forward for energy investment.


For a free consultation about co-location and your energy investment, call +44 (0) 20 3051 0600

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.

The Open Energi Podcast – Lessons from the 2019 Blackout

The blackout that struck the UK on the 9th of August 2019 was a once in a decade event: a lightning strike causing near simultaneous drops in output from both a conventional gas power plant and the UK’s largest offshore windfarm.

This led to widespread blackouts and travel chaos in London as passengers were left stranded on depowered trains. It also raised conversations about the systems necessary for the stability of the UK’s power grid into the mainstream.

Open Energi has been actively working for over ten years helping the UK’s National Grid deploy the technology and software necessary to underpin a reliable renewable power network.

Our first podcast features insight from Dr Robyn Lucas, Open Energi’s Head of Data Science and Sebastian Blake, Head of Markets and Policy, as they discuss what made this blackout so important as a moment to reflect on the evolution of the UK’s power infrastructure, including:

  • how systems designed to offer resilience to the grid responded (or failed to respond) to the blackout.
  • how assets – like batteries – are managed through software to react to both changes in frequency and market prices.
  • the most important lessons emerging from the blackout and subsequent investigations for everyone looking to help answer the UK’s future energy needs.

Listen here:




Here’s to the end of coal. But the revolution in energy is just beginning.

This article was originally published on 18 June at Open Access Government

David Hill, Commercial Director, Open Energi talks about the necessary infrastructure required to achieve the government’s ambitious net-zero emissions target and whether the hype matches reality

At precisely 3.12pm on Friday 31st May, the UK went two weeks without burning a single lump of coal for the first time since the Industrial Revolution. Social media channels buzzed with the #coalfreefortnight as commentators across the energy policy spectrum chose to mark the occasion with a tweet.

We’ve come a long way since the ‘dark satanic mills’ of William Blake’s iconic poem. It is right that we celebrate milestones like coal-free fortnight. But consider this. It has taken the UK 130 years finally to turn its back on coal. With the spectre of climate change looming larger and more tangible by the day, we must ask ourselves whether we are moving fast enough and smartly enough to deliver the revolution in energy delivery required to satisfy future demand while protecting the planet?

Renewable energy, comprising wind, solar, and biomass generation hit 42GW in the UK last year, accounting for 33% of total capacity. Meanwhile, analysis by Carbon Brief suggests up to 50% of the UK’s electricity could come from renewable energy by 2025. Progress at this level is encouraging. But integrating this level of renewables cost-effectively is challenging. Unlike traditional thermal sources of power, turning wind and solar on and off according to demand is simply not possible. Sceptics are also quick to raise the question of what to do when the sun doesn’t shine, and the wind doesn’t blow.

A smart solution to a complex challenge

When dealing with intermittent supply, such as wind and solar power, flexible capacity management becomes a fundamental need and challenge. The goal is to reach a point where we no longer require polluting power stations to ‘fill in the gaps’ when wind turbines and solar powers aren’t generating.

Achieving this requires energy storage to act as a buffer, easing pressure on demand when supply is too low, or saving valuable energy from renewables on a very windy, or sunny day where too much energy is being produced.

Most people associate energy storage with batteries. Battery storage systems allow energy consumers to store low cost, renewable energy and deliver it back at times of peak demand. For example, if you have a battery storage system integrated with a solar farm, it is possible to use photovoltaic (PV) power to charge up the battery for free during the day, drawing on that power at peak times, or selling that power back to the grid.

Applications for energy storage projects in the UK have grown from 2MW in 2012, to over 6.8GW in 2018, according to trade body RenewableUK. Little wonder, as batteries are already proving their value in helping organisations save money on power while doing their bit for the planet. But in our pursuit of low-cost clean power, arguably the cheapest and cleanest type of energy storage comes from the pockets of flexibility in our demand for energy.

Finding the hidden pockets of flexibility

Demand-side flexibility involves getting energy consumer to change their energy consumption patterns based on certain market signals. A lot of us practice a version of this already at home. For example, we switch lights off when we’re not in a room, or we use the washing machine at times when energy is cheaper.

The same applies at an industrial scale. Think about a supermarket fridge, an industrial furnace, or a water pump that feeds a local reservoir. The electricity consumption patterns of these types of devices are not necessarily time-critical. Provided they operate within certain parameters – such as room temperature or water levels – they can be flexible about when they use energy.

When electricity demand outstrips supply, instead of ramping up a fossil-fuelled power station, certain types of equipment can defer their electricity use temporarily. And if the wind blows and too much electricity is being supplied, then instead of paying wind farms to turn off we can ask equipment to use more now instead of later.

That sounds simple enough, but imagine trying to do this at scale, often with multiple assets on a single site, all with varying requirements. It would be virtually impossible to manage, and completely impossible to scale. Until now.

An automated approach to grid flexibility

Artificial intelligence and machine learning techniques are enabling us to keep an eye on multiple assets on a site, consider all the variables, from weather forecasting, through to pricing, and then make a series of intelligent, real-time decisions on how and when these assets should be using energy.

In the UK alone, we estimate there are 6 gigawatts of demand-side flexibility which can be shifted during the evening peak without affecting end users. Put into context, this is equivalent to roughly 10% of peak winter demand and larger than the expected output of the planned Hinkley Point C – the UK’s first new nuclear power station in generations.

Get low-cost, clean energy – with your car

Things become even more exciting when we add electric vehicles into the mix. Imagine if the charging points we used to charge our vehicles at home run on a system connected to technology which pinpoints the optimum time to charge the battery. Cars could help to absorb energy during periods of oversupply and to ease down demand during periods of undersupply. Your car would effectively become an energy storage unit that could help power your house with clean, low-cost energy.

Thanks to rapid advances in technology it is possible to envision a fully autonomous, self-balancing grid which delivers all the clean energy we need, incredibly cheaply. This is not decades away. Everything I have mentioned exists, is proven, and is scalable.

We’re forecasting up to 30GW of capacity in the UK by 2030, stemming from a mix of energy storage, combined heat and power units (CHPs), electrolysers and Electric Vehicles, through to more traditional demand-side response assets such as industrial pumps, boilers and chillers. Our technology already enables us to address all of these assets, unlocking potential cost-savings of up to £8 billion per year by 2030. When you begin to think about the opportunities this unlocks, it starts to put the long, slow demise of coal into perspective.

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.