Transparency and opacity in battery revenues: We’re not making this stuff up... (but they might be)

Transparency

Much of the energy industry is backed by masses and masses of data – the physical operations of individual plants, the market participation of operators, the resultant clearing/trading prices of these services/markets. Much of this data is widely and publicly available and can be observed, downloaded, analysed and more-or-less picked apart with a fine-tooth comb.

Through the NESO Data Portal, one can extract the market results for Ancillary Services (DFR, BR, QR, etc.) and some physical properties of the UK energy system (e.g. system frequency). Day-ahead trading market prices can be observed via the Epex Spot website, and services exist that collate historical data for almost all energy trading markets such that a full historical view of prices can be gleaned. The Balancing Mechanism Reporting Service (BMRS) portal from Elexon offers an in-depth view of Balancing Mechanism (BM) activity – the physical actions of BM participants & their instructions from the BM. The EMR Delivery Portal publishes a view of Capacity Market prequalifications and agreements. Again, multiple services exist that can be used to extract further market prices (e.g. BM accepted Bid/Offer prices) and activity to paint a reasonably accurate picture of any one participant’s actions at almost any given time in the past.

From this, one may conclude that market activity is transparent. However …

Opacity

Where service revenues can be reliably extracted for BM, Dynamic Frequency Response (DFR), Balancing Reserve (BR), Quick Reserve (QR) and Capacity Market (CM) – trading revenues can only be inferred based on the physical activity of a battery. The published Physical Notification (PN) data on BMRS details the intended charge and discharge power, per half-hour, in addition to any BM Bid/Offer instructions issued to a battery. These PNs can be explained by an array of actions (e.g. state of charge rebalancing while delivering DFR) but essentially represent trading activity – a negative PN implies a buy, and a positive, a sell. Current market trends indicate that around 80% of a grid scale batteries revenue comes from wholesale markets/trading. But how accurately can trading revenues be reported, unless explicitly published by the trader themselves? Herein lies the opacity in battery revenues!

An initial view can be taken by applying the Epex or Nord Pool day-ahead (hourly resolution) prices against all PN positions. This can be a fair assumption as the majority of battery trading activity will go through these markets. Inaccuracies can arise, however, when a half-hourly position is declared, as clearly that kind of activity could not be attributed to a market that trades at an hourly resolution. With this, one could take an average (or volume weighted average) of the intraday trading price and apply that to any half-hourly trades, leaving the hourly trades to day-ahead markets. This is a reasonable approach that covers most situations but, as good as it may be, is still a fairly broad assumption.

Complexity

This is because the inferred revenue can misrepresent the actual achieved revenue quite significantly. Take, for example, the trading market prices on January 22nd 2025; on this day, the system margin was forecast to be quite tight (the margin between supply and demand had a high likelihood of nearing Capacity Market Notice (CMN) trigger limits). As such, the day-ahead auction cleared at very high prices, the hour starting at 17:00 cleared at £620/MWh! As the day progressed, it became more apparent that system margin was well within limits (i.e. no CMN was triggered) and subsequently the intraday trading markets saw weighted average prices for the half hours starting 17:00 and 17:30 clearing at around £190/MWh and £210/MWh respectively.

If a 50MW (100MWh) battery, with a CM obligation of 13MW, secured day-ahead trades for 4 hours over the afternoon peak (a strategy to secure trading revenues over a potential CM event), for the hour starting 17:00 they would have earned £8,060 (13MW x £620/MWh x 1hour). If, as was the case, the day progressed without a CM event and they entered the evening peak period with a 75% state of charge, there would be 25MWh of remaining capacity that could be sold during the intraday market. If the strategy was to weight the volume sold by higher prices, and 3MW was sold at 17:00 for £190/MWh followed by 4MW for £210/MWh at 17:30, the total revenue for that hour would have come out to £8,765. However, externally, all that can be observed within the PN data is a position of 16MW for 17:00 and 17MW for 17:30, and with no other method to discern which market was traded, following the assumption that this was performed in intraday is the best guess. This would result in a revenue of £3,305 for that hour, less than 40% of the true value.

Of course, this is an extreme example - price swings of £400/MWh are not frequent between day-ahead and intraday trading markets. But, it does indicate that estimated trading revenues based on PN declarations become far less accurate when intermarket prices become more volatile – and this doesn’t even consider non-physical trading where, in the example above, it would have been possible to buy back the full volume of the day-ahead trades in the intraday market for a profit in all settlement periods, submitting PNs of zero for the entire 4 hour period – leading to an observable revenue of £0.

Battery revenues are complex, covering multiple markets, limitations and operator strategies. A lot of clarity can be gathered from the available data provided in public industry sources, but the finer details and intricacies of potentially the largest share of battery revenues – wholesale trading – are very difficult to extract!

An argument for Pay-as-Bid v. Pay-as-Cleared

At the excellent Energy Storage Networks Annual Conference last week in London, energy minister Michael Shanks spoke very well about the recently issued NESO document: Clean Power 30.

When asked whether the vision he had set out of CP 30 would break the price link for gas with power he didn’t answer that particular question, but did say some gas would still be needed. Indeed, the NESO CEO Fintan Slye claims in his introduction that we will have “home-grown energy that breaks the link between volatile international gas prices”

This is borne out at the top of page 7 of that CP 30 report: ‘A clean power system is one where demand is met by clean sources (mainly renewables), with gas-fired generation used only rarely to ensure security of supply, primarily during sustained periods of low wind’.

Now, imagine we still have the same market structure in 2030 as we do now i.e. pay as clear.

Do we think this gas plant is going to be happy sitting around twiddling its thumbs and waiting for its moment in the sun? Because by 2030 the load factor it’s running at, if it’s just confined to these low renewables moments, will be very low – 10%? 20%? Therefore in the moments when gas plant does get to run, it needs to make hay to justify being kept on-line. Meaning it will extract as much scarcity value as it can, so that when it gets called, it will need to charge very high prices to justify being kept online. And as we know under pay as clear, all generation then gets that price.

So the gas price-power price link will NOT be cut, as the NESO report asserts – without market reform. Let’s look at this.

The day ahead (DA) and on the day power(M7) markets are run by exchanges. A significant amount of power is traded DA, with a lot of the activity in M7 being adjustment trades (as forecasts change), or pure speculative trading by trading houses.

The DA market currently gets its price for each half-hour (HH) via the pay as cleared mechanism. This means all bids and offers (buy orders and sell orders) are submitted until the TSO, in conjunction with the exchange, has matched up enough bids and offers to meet the forecast demand for a particular half-hour. The last MW of power offered in to meet the demand sets the price for all the power offered in to meet the demand. Pay as cleared results in the plant at the margin being the price setter for the whole HH – and this mechanism thereby creates super-profits for plants with a low marginal cost, such as nuclear and renewables. These low marginal cost generators will always offer into the market power at low prices to ensure they get called in the generation stack, knowing they will get a higher price.

This is illustrated below:

The UK within day market, M7 however, is a ‘pay as bid’ (PAB) market’ – which means a generator needing to sell has to be offering at a price that is likely to trade – if it gets too greedy it may be undercut by other plant and fail to sell (and therefore generate). Similarly a buyer needs to put in realistic buy prices in order to trade – or risk paying imbalance costs (with all that attendant uncertainty).

Having a market which is predominantly pay as cleared results, as can be seen in the box above, in a material transfer of value from consumer to generator. When we get to the situation where there are only a very few gas generators left, and they only run intermittently (rather than baseload) they will be sure to extract maximum scarcity value at times of system tightness – which will result in some fairly eye-watering prices if the continent is tight also, and the ageing French nuclear fleet is running below par.

This is of course why an island like the UK needs as many interconnectors to different parts of the continent as possible – the ultimate flexibility.

The risk of these sort of spike highs could be alleviated at a stroke were the DA market changed from pay as clear to pay as bid, and this does mean that both buyers and sellers have to become more precise in their pricing, rather than just lazily offering in and getting best price whatever. Note that the BM is also a pay as bid market which, given the added locational element of BM, uncertain run times, and skip rates makes the pricing precision even more challenging.

In conclusion, pay as bid would involve a substantial change to the way we trade energy in the UK – but logically, it’s the only way to break the power price link to the gas price in our system.

Battery developers get understandably animated about their project costs, but what often gets left behind as an afterthought is the battery warranty, which should be every bit as important as the main body of the contract – after all, they have a material role in influencing how your battery will be operated.

But are they of real value – or merely a fig leaf of assurance?

Too often the battery owner, or their chosen optimiser, look at this too late and may discover it is either incomprehensible, too restrictive, has too many facets – or all of the above. Conversations I have had with owners at trade meetings have shown a degree of coyness about details such that I suspect there are a broad range of warranties – some good, some not so. But let me say it here – it pays to give your warranty the utmost scrutiny, and if you are a route to market provider even more so, because you need to make a realistic assessment of how practical and workable the warranty is before making a commercial offering, so as to avoid underperformance, and possibly an expensive damages claim.

Treating your battery ‘well’...

So let’s think about the warranty. It’s a guarantee from the manufacturer that your battery is going to last the length of time the salesman said it would, with a certain capacity after a number of years, if you treat it well. ‘Treating it well’ in this context means managing the battery health sympathetically, and the warranty will definitely point you down that road. The manufacturer will be understandably wary about guaranteeing too much, and is likely to quiz you, the purchaser, in some detail about the use case. From this the warranty will typically confine you to a number of cycles a year, as well as some depth of discharge/ charge metrics, and maybe some other items.

However, predicting the use case is a challenge: what a 2 hour battery is doing now compared to what it might be doing in 2 years is very difficult to predict, never mind in 5 or 10 years. Are you going to restrict chasing lucrative revenue moments from new services or market volatility because of the warranty? Or will you chase the $ regardless? After all, you have a rate of return to make.

And then let’s suppose you DO scrupulously observe your warranty conditions throughout the year and at year end the manufacturer arrives at site to do a capacity test. And suppose the capacity is lower than expected in the warranty. At this juncture the warrantor will ask you, the owner, to prove all aspects of how the warranty conditions were observed throughout the year before offering any redress. These conditions can cover yearly cycle count, average Rest SOC, average charge power, average discharge power, depth of discharge – and maybe more.

Conditions, restrictions and redress

It is quite possible to imagine getting into a protracted argument about why the battery state of health isn’t what it’s supposed to be at the annual capacity test and more crucially, why not. How that redress is made will be in the warranty conditions and can be quite unspecific or vague, so it pays to examine the restrictions and redress language in close detail in advance so as to avoid protracted legal wrangling in the event of a claim. Loss of earnings is extremely unlikely to be part of a warranty and in any case would be difficult to prove. Furthermore, it is quite possible to imagine getting into an argument about WHY the state of health isn’t what it’s supposed to be at the annual capacity test and more crucially, the reasons this has happened.

Unless you have a very clear warranty in terms of default and remedy, you may find that you have no more than fig leaf protection.

Octopus recently announced their new battery lease agreement (also called a tolling agreement) with Gresham House, whereby they will manage 900 MWh of Gresham House’s portfolio. This news got me thinking about the nature of commercial agreements offered to battery owners by route-to-market providers, or aggregators for short.

TOLLING AGREEMENTS

Let’s start with the tolling agreement – it’s essentially a rental agreement for the renter to do what they like with the battery, within warranty confines. My first question is about the motives of the battery owner. We invest in batteries either to profit from market price volatility, or to mitigate volatility, so Gresham, by investing in batteries, are buying volatility and value their portfolio according to the financial modelling that reflects that. To give up all the upside that granting a tolling agreement does, means that either a) the tolling value is considerably above the valuation of those assets that they have in their books, or b) they think there is a significant risk that volatility is going to decrease over the tolling term. And, of course, the opposite is the case for Octopus.

Tolling agreements therefore aren’t that prevalent because typically the buyer doesn’t want to risk a monthly committed payment at the level the toller wants or needs, which is unsurprising given how variable battery incomes are month to month. However, there is probably more scope for specific tolling agreements – for example, we would consider offering a call option through the winter at a strike price on a particular block – say block 5, for example. This is useful to some market players, like suppliers, and involves a far lower level of financial commitment.

THE FLOOR

The next level of commitment, and a greater level of risk sharing, is the floor. With a floor, the battery owner is guaranteed a minimum monthly revenue and a proportionate share of anything made above that level in the month. This means the storage owner is in a position to benefit from any upside should the month prove volatile, and the offtaker (the one buying the resources) is taking less risk in terms of guaranteeing payment, as payments will be less than under tolling agreements. Let’s not forget that in the purely merchant market that battery storage operates in, these guaranteed payments have material cashflow implications for the aggregator, a fact that asset owners need to think about when choosing a counterpart. So, the ratio of risk and reward changes here, tilting slightly from the aggregator to the owner.

CAP AND FLOOR

A variation to this arrangement is the cap and floor, where the owner gets the first portion of the month’s income, the aggregator the next, and then above a certain level (the cap), the two parties share the upside on a proportional basis.

MERCHANT REVENUE SHARING

The last type of agreement in common use is the pure merchant revenue sharing arrangement. In this case, the owner stays completely exposed to market upside – and downside – possibilities, and relies on the aggregator to deliver the maximum revenue possible, for which they will earn a share of the rewards. Thus, there is considerable risk for the owner in the choice of aggregator, and whether said aggregator can deliver on their promises – whilst for the aggregator, this arrangement is in the nature of a free option, barring their operational costs specific to the asset. In this arrangement, the aggregator only earns a small percentage of the net revenues.

As more and more batteries come online, owners will weigh up the size of the opportunity against the risk in the various arrangements, and the beauty of them is that the levels and revenue share proportions can be played with and adjusted until a mutually acceptable arrangement is reached. The only real limitations are a) on the aggregator side, the arrangement has to be sufficient to meet the costs of integration (not inconsiderable) and operation, and b) on the owner side, the requirement for a minimum investment return.

Hello and welcome to Ecotricity Smart Grid’s newest product launch - Ecolibrium.

Ecolibrium is, essentially, our Virtual Power Plant (VPP). We developed it to enable the batteries we’re developing to have a route to market. We didn’t want to use existing aggregators because – to be honest – we looked at what was on offer and didn’t think it was very good, in terms of contracts, transparency, risk-reward balance - but most importantly, in terms of ‘good’ optimisation.

What do I mean by ‘good’? I mean an optimiser that can assess all the revenue possibilities and consistently make decisions that create the best possible revenue outcomes alongside sympathetic battery utilisation.

We quickly realised that the models and platforms we were building had broader applications than just batteries – they could also be used to opportunistically turn down generating assets against revenue opportunities from the Balancing Mechanism or system imbalance price. And we have done this very successfully, as well as partaking in the Grid’s ‘pandemic scheme’, the Optional Downward Flexibility Mechanism, when demand crashed.

So here we are – with architecture and a platform suitable for not only our assets, but for anybody’s asset or battery. Indeed we’ve been running a co-located solar-battery site in South Wales for the last 2 years as we’ve been developing our models and platform.

I’m genuinely excited by this development, which has been painstakingly created over the last 4 years. We have some really smart and engaged people who understand the energy and tech space, we have an insightful revenue estimation model where clients can get a realistic revenue estimation for their assets. And last but not least, we are very transparent – so our clients always know exactly what’s going on with their assets and why, through their portal account on our website.

What is Flexible Energy and Why Do We Need It?

The National Grid Electricity System Operator (ESO) is tasked with balancing the supply and demand of electricity on the grid every second of the year to keep it close to 230 volts and 50 Hz. Energy flexibility refers to the ability to adjust generation or demand to maintain this balance. To be compliant with Net Zero targets, the methods of achieving this balance are evolving.

Changes in Generation

If we look back to 2008, Britain’s electricity generation was dominated by power plants running on fossil fuels, which accounted for three quarters of the fuel mix. While these traditional generators are dispatchable and can turn up and down to match the demands on the grid, they are also carbon intensive. Fortunately, there’s been a shift towards renewables, and last year saw more than half of Britain’s fuel mix come from zero-carbon sources. However, there is still more that must be done, and flexibility is key to unlocking the full decarbonisation of the grid.

Last year saw a significant milestone of wind and solar generation accounting for over a third of Britain’s energy. This shift towards renewables is changing the energy landscape as they’re intermittent sources of energy. As more and more renewable projects come to fruition, there will be greater variability in generation driving the need for flexibility - and the way in which the grid is operated must adapt to make the most use of these resources.

Increasing Demand

With the electrification of heat and transport, electricity demand is expected to rise. This will require increased system capacity and upgrades to transmission and distribution networks. However, this rise in demand also opens new opportunities for flexibility.

Types of flexibility

Energy Storage

One key source of flexibility is the conversion of electricity to other forms of energy which can be stored. Examples of energy storage include compressed air as elastic potential energy, pumped hydro as gravitational potential energy, flywheels as kinetic energy and BESS (battery energy storage systems) as chemical potential energy. These methods of storing energy vary in terms of the capacity of energy that can be stored, their power, efficiency, ramp rates and duration.

With decreasing costs and increasing energy density, BESS assets are rapidly being deployed across Britain. They offer high efficiencies and are instantly available compared to more traditional power stations, making them ideal for load shifting (from high generation to low generation moments) and frequency response services. Storage assets are the most versatile form of flexibility as they can be utilised to both increase or decrease demand and supply.

Supply Side Flexibility

During periods of high demand, the traditional form of flexibility is the use of gas peaking power plants which increase the supply when called upon. However, the supply side of flexibility also includes renewables such as wind and solar. They may be entered into the Balancing Mechanism so that they can be turned down when generation is greater than the demand for power or if there are network constraints. Additionally, wind and solar sites may be co-located with a BESS asset which unlocks further flexibility.

Demand Side Flexibility

Electricity demand follows typical profiles which follow daily, weekly and seasonal patterns. Demand side response alters this profile to shift load from peak to off-peak periods. Certain industrial processes are well suited to this load shifting and in recent years a more distributed domestic approach is beginning to emerge. Time-of-use tariffs are one such example whereby EVs, domestic batteries and heat storage can have smart controls to allow flexibility in this space.

Interconnectors

Interconnectors are the sub-sea cables that link up Britain’s electricity system with neighbouring countries. The flow of electricity is dictated by the markets, meaning it will flow from systems with low prices where there is high supply/low demand to systems of high prices where there is a low supply/high demand. In a similar way to the Balancing Mechanism, the ESO is also able to utilise in the very short term the flexibility of interconnectors to ensure the system is balanced.

What We’re Doing

Here at Ecotricity Smart Grid, our team of energy, software and data experts have developed Ecolibrium. As the name suggests, this is our service which helps the ESO to keep the system in balance. We act as a route-to-market for energy storage and fossil-free generators. Ecolibrium connects to these assets and dispatches them according to the best-suited market or service at any given time.

Far too early, one Tuesday morning in May, four members of our team embarked on a very long train journey from Stroud up to Glasgow for the All Energy Show 2024.

We always love the opportunity to have a stand at a show. Being surrounded by innovators and industry leaders to showcase the latest advancements in renewable energy technologies always excites and inspires us, and our team had the pleasure of engaging with many brilliant minds across the sector.

Thank you to everyone who visited our stand and took the time to talk with us. It's exciting to be able to discuss battery optimisation, energy storage systems and renewable energy innovations with likeminded people, and potential new customers who are as interested in flexibility markets as we are passionate about them.

If you missed us don't worry, next up we're staying a little closer to home and heading to Solar & Storage at the Birmingham NEC where we will be taking our freshly launched branding out for its first trade show spin!

We will be heading to Solar and Storage live at the NEC in Birmingham on the 24th-26th September.

Come and visit us at stand P71c to discover how we can deliver flexibility revenues for your asset.

We’ll talk you through our approach, both commercially and technologically, and share our philosophy. Our in house developed platform is a virtual power plant which connects electricity generators, consumers and energy storage systems to a single digital platform to vary load as needed. Our proprietary models and AI-based forecasting enables them all to work together to create a more sustainable and secure energy grid - with supply and demand balanced with National Grid requirements.