Battery Storage

5 mins

The economics of behind-the-meter battery storage. Part 2: Earning value in energy markets

A quick recap

Behind-the-meter battery storage can create value for a C&I business in four ways. By:

Reducing energy supply costs
Earning revenue from providing market services
Providing network capacity (as an alternative to traditional network infrastructure)
Delivering reliability (backup power), so critical loads can continue to run when there is a supply interruption.

In Part 1 of this blog series we looked at the various ways that a battery can help reduce a site owner’s energy supply costs, including some worked examples based on different energy supply arrangements.

Reducing energy supply costs is an obvious and sensible starting point, but as the post highlighted it can be pretty hard to make a battery investment stack up if that’s all the battery is targeting. In most situations the price signals available are just not sufficient to achieve a reasonable payback.

Fortunately for prospective battery owners, there are other value streams to tap into and in this post we’re looking at the potential to earn revenue from providing market services. But what exactly do we mean by that?

What are market services?

These are revenue making opportunities offered up by the wider energy system that a site is connected and exposed to.

Historically, access to these opportunities has often been limited to utility-scale projects or only the largest energy users, but recent regulatory reforms in markets like the UK and Australia mean smaller assets within the distribution network, like behind-the-meter battery storage, can increasingly participate in these markets.

The four areas of opportunity are:

Energy: Provision of wholesale energy or energy price arbitrage
Ancillary: Other market services like frequency control and balancing
Network: Flexibility services to manage network constraints
Capacity: Provision of capacity to the system operator

Whether a battery storage asset can access some, all or none of these will depend on what country and market we’re talking about. Some regions like Australia’s NEM don’t have a capacity market, so that revenue opportunity is off the table right away. On the other hand, it’s easier for small assets to participate in frequency markets in Australia than in the UK or Europe.

The other limiting factor on market-based revenue is whether a suitable “route to market” exists. So if I’m a C&I business with a battery, will someone actually support me in participating in markets.

Every C&I site is ‘represented’ within wholesale energy markets by an energy supplier or retailer who is paid to supply electricity to the site, but traditional suppliers have not been inclined to facilitate access to these areas of opportunity (read about the role of electricity retailers).

Regulatory reform has been helping in this regard by increasing competition and opening up access to other market participants to offer route-to-market for these opportunities.

In Australia, regulations like Small Generation Aggregation, Wholesale Demand Response, new market roles like Market Ancillary Service Provider, and the ability to take ‘child meters’ within embedded networks ‘on-market’ all provide new routes to wholesale markets.

In the UK the P415 rule change was enacted recently, which enables third-party aggregators to provide a route-to-market independent of the supplier of electricity to the site.

P415 in a nutshell

The P415 rule change, implemented in November 2024, amends the Balancing and Settlement Code (BSC) to allow Virtual Lead Parties (VLPs) and Virtual Trading Parties (VTPs) to participate directly in the UK's wholesale electricity market, enabling aggregators of demand-side flex, like a BtM battery storage system, to offer flexibility services independently of suppliers. Watch this video for a detailed introduction: The P415 Code Modification.

Let’s get into the detail

Next up we’ll talk through the four opportunities in more detail, discussing what they are, how they work and provide a high level figure of what they’re likely to be worth to an example C&I business in the UK.

We then go on to dig deeper into the modelling approach used to come up with the value estimates. Finally we summarise the value for each market opportunity and compare those numbers back to our base case, which is the battery working to reduce energy supply costs, to get a sense of if the extra complexity of accessing these services is worth the bother.

Important note: we’re going to be running detailed simulations to generate these revenue estimates. The simulations are both highly specific to the particular site, connection, load shape, asset sizing and contracting arrangements used, as well as to the modelling approach adopted. In this case all simulations are run with perfect foresight and as such revenue estimates represent the maximum that could be achieved.

Wholesale or spot market arbitrage

What is it?

The battery can directly access and trade in wholesale energy markets. The volatility that’s present in these markets is typically much more extreme than any price difference offered within a conventional C&I energy supply contract, even one with time-of-use charges.

Historically, energy users would avoid exposure to such volatility - it was something they paid a retail supplier to worry about for them (at a cost of course!) - but battery storage systems are flexible enough to take advantage of volatility, and direct wholesale energy market access is one way to capture the value of this flexibility.

In 2024, the average daily spread in the GB day-ahead hourly market was £54 per MWh, or 5.4p per kWh, with a maximum of £341 per MWh or 34.1p per kWh. By contrast a typical spread in a C&I retail supply contract in 2024 was more like 1.5p per kWh. Remember, we’re talking about the energy commodity cost here, not network charges et al.

The graphic below shows the intraday price for a typical C&I business tariff in the UK during 2024 (purple trace) compared to the underlying day-ahead wholesale market. As you can see the average wholesale price across the entire year (orange trace) aligns closely to the retail tariff but displays more variability. Looking at particular months of the year there was even more exaggerated price variability for a battery to take advantage of..

If you recall from Part 1, a battery needs a healthy “daily spread” in prices to generate a good commercial return. So by exposing the battery to these wholesale prices, either by electing to move to a tariff with direct market exposure, or by leveraging recent rule changes like P415, the asset can generate significantly higher value than if it’s only exposed to conventional supply arrangements.

This revenue opportunity increases in regions that have multiple wholesale energy markets, such as the UK and much of Europe.

Here the battery has the opportunity not just to trade within a single market but to trade between multiple wholesale markets where each market has a different gate closure and often a different trading resolution.

For example in GB, a battery might choose to charge (buy) in the day-ahead hourly market but then discharge (sell) in the continuous intraday 30-minute market. It might do this because prices increased significantly due to changes in short term weather forecasts.

You can see an example of this from a real day of wholesale market trading, this from October 28th 2024, where the spread available from trading between markets is significantly higher than the opportunity of trading within any one market.

Watch this video for information on the three wholesale energy markets in GB.

‍What might this be worth?‍

If our supermarket was to install a 500kWh/250 battery and expose the site to day-ahead pricing, plus the normal non-commodity costs, then the battery could generate value of around £9,900 per year.

If the supermarket were to operate the battery in line with P415 via a Virtual Lead Party (VLP) it could generate value of between £9,600 and £12,800 a year, depending on how it trades in the wholesale markets.

Frequency, balancing and ancillary services

What is it?

Energy markets don’t just involve the buying and selling of the energy commodity, they also require a range of additional supporting services to keep the lights on. Often these services are procured by the System Operator, so that’s AEMO for Australia and NESO in GB.

Probably the most common example of these ancillary services is those associated with maintaining grid frequency. In Australia this suite is referred to as FCAS and covers 10 sub-services, five for raising frequency and five for lowering. In GB the main suite is referred to as Dx - D for Dynamic - and includes 6 sub-services, three up and three down although there are other ancillary services in addition to these.

These markets typically have very particular rules that accompany them and that assets looking to earn revenue from them need to abide by. These rules will include:

which sub-services can be “stacked” together
the duration that assets must commit to each market
minimum bid sizes
energy headroom and footroom requirements for the battery
and more besides

Additionally there are high-speed metering and data requirements for assets participating in these markets that amount to a pretty high barrier to entry. Nonetheless, in markets like Australia's NEM small-scale battery storage assets routinely earn frequency market revenue.

For now we haven’t included the Balancing Mechanism, but in GB this is certainly a potential option for the BtM supermarket provided they have had a large enough portfolio of similar assets in the same GSP group. Last year NESO relaxed some of the high operational metering requirements for portfolios of aggregated assets, which improves the accessibility of this market for smaller flexible assets like the battery at our supermarket.

‍What might this be worth?‍

The focus of this post is the UK market where smaller behind-the-meter assets typically don’t participate in frequency markets and for that reason we’re not modelling frequency revenue for our supermarket.

On top of that, these markets are now heavily saturated in GB, and increasingly saturated in other regions like Australia’s NEM, and contribute a decreasing chunk of the value stack even for utility-scale assets.

Flexibility services to the network operators in response to localised constraints

What is it?‍

Network operators own the pylons, poles, wires (conductors), substations, and transformers that deliver electricity from where it’s generated to where it’s consumed. This infrastructure is subject to physical limits on the amount of energy that can be delivered at different times.

A simple example might be the addition of a large industrial park on the edge of town. It’s connected to the local substation that is supplying lots of other customers and so with the addition of this extra electrical demand it gets close to its capacity on a few afternoons each year, perhaps when it’s very cold or very hot and everyone is using their heating or cooling.

Historically, the network owners would expand the capacity of the substation, which would be time consuming and expensive. These network businesses earn regulated returns on their asset base, which means that this kind of augmentation will increase costs for network users. Regulators require networks to consider whether there are more economically efficient alternatives to this traditional augmentation, but this has not commonly occurred in the past.

Increasingly networks are now considering what are sometimes called ‘non-wires alternatives’ or the procurement network support services, for example procuring flexibility from the homes and businesses already connected to the substation. If these network users can reduce their load on, say, the few afternoons each year where the constraint is forecast to be breached, then this can avoid the time and cost of expanding the substation. One way this load reduction can be achieved is for a battery storage system to discharge into these afternoon peak demand events.

This is now commonplace for the distribution network operators (DNOs) in the UK due to improved regulation and the emergence of new ‘flexibility marketplaces’ that make the contracting of these services more efficient. This is still an emerging trend in Australia and other parts of the world.

‍What might this be worth?‍

Each DNO that procures flexibility in this way will offer contracts based on:

How much flex they need
Which direction they need it - often that’s flexing down demand but in areas with high amounts of rooftop solar that can also mean flexing up
How many hours a year they require the service

They’ll then reward flex providers based on a combination of availability payments and utilisation payments, sometimes using a baselining methodology to guestimate how much flex you delivered for them, sometimes using direct metering on the flex assets.

The payments vary a lot and are highly locationally dependent but if your site is connected to a part of the network where these contracts are offered then a rough guide would see you earning between 3p and 25p per kWh for each unit of energy delivered into the flex program.

For our supermarket we’ve assumed a “demand turn down” service value at 3.7p/kWh which is the published rate for LV connected sites by UK Power Networks. This requires a battery to discharge during winter afternoons when it makes commercial sense to do so. On that basis it earns between £475 and £2,300 a year depending on the other price signals the battery is working with.

Earning capacity market revenue

What is it?‍

If a site operates within an energy system that includes a capacity market then there can be additional opportunities to earn revenue. Examples of capacity markets include GB and the WEM in Australia.

The principle of a capacity market is simple enough: Assets that can provide generation capacity can earn annual payments for that capability. The revenue they received is recovered from energy users, the precise mechanism of which varies from market to market.

How much revenue an asset can earn is based on the nameplate capacity of the asset, multiplied by a derating factor to reflect its ability to provide capacity when the system will need it most. Watch this video for an introduction to capacity markets, and this video for information on how capacity markets are modelled in Gridcog.

For example, in the GB market battery storage assets will earn 100% of their nameplate capacity if they’re able to provide continuous output for at least 9 hours. That’s a very long duration BESS. More realistically, a 2-hour duration battery can earn about 22% of its nameplate capacity (2024 T1 auction).

The nice thing about this revenue stream is that once the contract is secured it's very low effort, bar some regular testing to prove the asset could deliver that capacity. Fun fact: assets participating in the GB capacity market have never been called upon.

‍What might this be worth?‍

For our 500kWh/250kW battery, when derating factors are applied it can earn £4,750 over 2024 from the capacity market. That’s based on T1 2023/24 prices from January to September and 2024/25 prices from October to December, with corresponding derating factors applied for each auction period.

Bringing it all together: is the lemon worth the squeeze?

Accessing the value streams discussed in this article does come with a higher degree of difficulty compared to capturing the behind-the-meter value we explored in Part 1 of this series. So is it worth it?

Our base case battery: reducing conventional energy supply costs

Using our supermarket in Maidstone as the example site we start with a simulation comparing the total energy supply costs for 2024 with and without a 500kWh/250kW battery storage system. Solar is deliberately not included in any of these simulations. The focus is purely the battery storage system working with the available price signals.

Adding solar into the mix will potentially improve the business case for the BESS but typically only if that solar is fairly significantly oversized and hence providing the battery a cheaper alternative to importing from the grid for charging.

The energy supply arrangements include a time-of-use commodity charge and then passthrough of the non-commodity costs for a total annual spend of £85,715.

Energy costs after installing the battery are reduced to £73,563 so the battery generates value of £7,152 over the year. Keep this figure in mind as it represents the baseline value against which we can compare our market driven options.

Switching to energy supply costs with wholesale market exposure + capacity market + DNO flex

Let’s start by swapping out the retail supply contract to instead purchase the energy commodity from the day-ahead wholesale market. As we mentioned up top, this provides the battery with access to the higher volatility that’s inherent in wholesale markets. We also include participation in the capacity market auctions.

You can see that our baseline costs are nearly identical to our traditional retail supply arrangements. That makes sense as retail supply tariffs are derived from the underlying wholesale market pricing.

Energy costs after installing the battery are reduced to £71,117 (including the capacity market revenue) so the battery generates value of £14,615 over the year, more than double our base case.

Giving the battery full market access via P415 + capacity market + DNO flex

Our final model takes a different tack and uses the recently introduced P415 rule change to take on more direct and aggressive exposure to wholesale markets.

P415 allows a behind-the-meter asset like a battery to operate largely independently from the energy supply contract. For Aussie readers it’s conceptually similar to an “on-market child” within an embedded network structure.

The battery gets market access via a Virtual Lead Party who can trade the battery in the market for maximum gain. The VLP will then share the revenue with the asset owner, in this case our supermarket.

Importantly, despite being located behind the main site meter (MPAN in UK parlance, NMI for the Aussies) the energy movements from the battery are backed out of the metering data such that the supply contract to the supermarket is mostly unaffected. The exception to this is the network tariff.

To reflect this in a Gridcog simulation we’ve added a second project participant, the VLP, and instructed the battery to maximise its returns from the wholesale markets whilst also minimising network costs for the supermarket owner.

Finally, we’ve compared a P415 arrangement where the VLP only trades in the day-ahead hourly market with a similar arrangement where the VLP trades all three energy markets, so day-ahead hourly, half-hourly and continuous intraday.

First up, the day-ahead only simulation:

In this model our battery generates a combined value of £16,639, a 130% increase on our base case. You’ll notice that the supermarket’s other energy supply costs remain unchanged. This is a key tenet of the P415 modification.

Now to include all wholesale energy markets:

In this final model our battery generates a combined value of £19,885. There’s significant extra value earned from trading between all three wholesale markets but also some reduced network tariff savings as a by-product of the optimisation having to make some choices.

We’ve summarised the value that could be generated by our supermarket battery under the different operating strategies below.

The wrap-up

In Part 2 of this blog series on the economics of behind-the-meter storage we’ve explored some of the additional market-based value streams that battery owners can access and what kind of financial uplift they might offer.

In Part 3 we’ll take a look at other ways batteries can earn their keep, specifically focussing on using behind-the-meter storage as an alternative to expensive grid connection upgrades, for example for businesses looking to install EV charging equipment on a site with a skinny grid connection.

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