Betting on Batteries: Why On‑Site Storage Is Smart for I&C

To paraphrase Benjamin Franklin, few things are certain in life, aside from death, taxes – and volatile power prices. While Franklin had few answers to the inevitability of death or how to evade government revenue collectors, his early experiments in battery technology have led to an increasingly compelling response to volatile electricity markets.

It's widely understood that energy storage, particularly using batteries, is going to be a crucial part of the utility-scale infrastructure we need to transition to net-zero power grids. But what is less well understood is that even small and mid-sized behind-the-meter battery systems can deliver attractive financial returns, while providing industrial and commercial (I&C) consumers in the UK with invaluable resilience to power cuts.

New modelling we have carried out shows that a 5 MW/5 MWh one hour lithium-ion battery system, costing around £4.5-5.0 million, is likely to pay back within five to seven years, while helping to protect the consumer against system instability. But crucial to that business case is a supplier contract that allows the owner to take advantage of the flexibility that a battery provides.

A more volatile world

As we discussed in a recent blog, intra-day power prices in the UK have become more volatile. In a system increasingly dominated by wind and solar systems – with very low operating costs – but where marginal pricing is determined by often high-cost gas-fired generators, intra-day power prices can swing from below zero to the hundreds of pounds per megawatt hour.

For consumers to take advantage of those price swings, flexibility is vital. Companies that can anticipate periods of high prices, and trim their demand, or ramp up consumption when prices dip, can make a significant dent in their electricity costs.

Only a relatively small number of companies can flex demand to a significant extent (those operating large refrigerators or with industrial processes where they can store or reduce production, for example). What most companies can do, however, is install battery systems to provide this flexibility.

Stacking up the revenues

The number of utility-scale battery systems has been climbing rapidly, as the government looks to reach its target of 27 GW of battery capacity by 2027, up from 5 GW in 2023. But battery systems do not need to be utility-scale to make commercial sense. Responding to volatile power prices, combined with revenues from a number of regulatory markets that reward the value that battery systems offer in terms of grid management, can make smaller behind-the-meter batteries economically attractive.

Modern battery systems can pay for themselves in a number of ways. There are four main revenue streams that we considered in our modelling:

Peak shaving: discharging the battery to reduce power imports from the grid during peak tariff periods.
Wholesale arbitrage: charging the battery when prices are low and discharging when prices are high.
Capacity Market: bidding the battery into the UK’s Capacity Market to provide despatchable power during periods of market stress.
Balancing services: participating in National Grid’s fast-response services, such as Dynamic Containment, Dynamic Moderation and Dynamic Regulation.

Our modelling was based on current UK market conditions and representative non-commodity costs and markets. These included costs such as Distribution Use of System (DUoS) charges, which can spike during peak periods, and payments from the Capacity Market and for balancing services. It also considered factors such as the round-trip efficiency of the battery (assuming 85% AC-to-AC), depth of discharge (below 90%) and a degradation rate of 2%/year, among others. It also considered capital expenditure variables, operating costs and inflation.

Model behaviour

Peak shaving accounted for around 50% of revenues, with balancing services providing around one third. Revenues from the Capacity Market rose over time, from around 10% of the total in year to roughly one-third by year 14 (we assumed a 15-year battery life). Wholesale arbitrage consistently contributed around 7.5% of revenues.

We considered base, conservative and optimistic scenarios, to account for uncertainties in costs and revenues. The base case suggested an internal rate of return (IRR) of around 15% and payback around six years. These figures were c. 23.5% and five years, assuming slightly lower capex, more favourable markets, and better performance.

The conservative scenario – where, for example, the system failed to participate in the Capacity Market, and prices prove to be less volatile – the IRR drops to 5% and payback stretches to 11 years. The investment would roughly break even by the end of its life.

Resilience – a free lunch

However, even under a conservative scenario, the battery system would provide a valuable service that the model doesn’t attempt to value: it would provide an uninterruptible source of power in case of a grid failure.

Blackouts have always happened. While some commentators have sought, with limited evidence, to pin the blame for Spain’s recent outage on renewables, the fact is that no power system is immune to sudden failure. Meanwhile, cyber risk and geopolitical tensions have raised the prospect of bad actors disrupting electrical grids – and outages can be cripplingly expensive for vulnerable businesses.

Batteries can provide a substantial buffer against a power outage, either providing a means to continued operations uninterrupted for a short period of time, or provide power to critical systems for much longer.

Counting on the contract

The favourable economics underpinning a behind-the-meter battery do rely on two important enabling conditions: a modern, dynamic supply contract; and operational integration of the battery into energy management systems.

The first condition is critical. To reap the benefits of a battery, the energy supply contract must have the flexibility to allow the customer to respond to market signals and capture the full value of these responses without adding to the risks and costs the supplier faces in supplying the site. Some contracts supply power on a fixed-price basis, with the supplier averaging their costs and applying a risk premium. Under such a contract, where the customer is insulated from time-of-use charges or pass-through of network costs, the savings generated by the battery drop precipitously.

Instead, consumers need contracts that provide half-hourly pricing, where the customer is billed on actual market rates that have been achieved by flexing demand. Most Suppliers offer their largest customers flexible contracts, passing wholesale power prices, DUoS charges and Capacity Market revenues through to the customer but integrated trading of flexibility on hourly or half hourly basis in response to price signals isn’t generally supported or encouraged. This is hardly surprising as many suppliers struggle to record and bill monthly wholesale trading activity accurately never mind hundreds of hourly trades.

Secondly, the battery needs to be properly integrated with energy monitoring, control systems and energy management. The owner needs to be able to respond to market signals – such as within or next-day price forecasts– and either manage the flexibility in house or use a third party to extract the maximum value from the market by either increasing or reducing its power demand over the course of the day. Again, the operational frameworks and systems that enable straightforward, proactive demand management that integrate seamlessly into a supply contracts aren’t generally available. To maximise returns from this emerging opportunity a buyer needs a combination of low-cost hardware in the form of a battery, an optimiser with a proven track record of maximising battery revenues of which there are many in the UK and a supplier that can support this activity and analyse the savings made by shifting demand from the normal pattern of consumption.