The business case for battery storage — does it still stack up in 2020?

 In News

The UK’s energy system is changing with renewable generators increasingly forming part of the energy mix and flexibility providers coming into their own to support the transition[1].

Storage assets currently have access to a number of potential revenue streams, which continue to fuel the business case for investment. In 2019, this saw the UK’s battery storage capacity increase by 70% and it is predicted that the market will grow by a further £6 billion by 2030.

What no-one could have predicted, however, is that 2020 would be dominated by the arrival of coronavirus and its impact on populations and economies across the world. But what has the virus and lockdown meant for storage asset owners? Here, we’ve analysed the data to see how key revenue streams have performed in recent months and what impact Covid-19 and other market forces may have had.

Wholesale Market

One factor that has a big impact on wholesale prices is the expected demand. This is driven by weather and the marginal generation unit required to produce instantaneous demand. Price spikes (Fig. 1) typically occur following extreme weather events (e.g “beast from the east”) when demand surges and more generators such as coal are needed. Power prices are also closely tied to gas prices (Fig. 2). This is because gas-fired generation is often the marginal source of generation.

Over the past year a gradual decline in prices can be seen and this trend has been further exacerbated since the UK entered a period of lockdown on 23 March (Fig. 2) and demand decreased. On average, wholesale prices during the first month of lockdown were around 40% lower than the same period last year (Fig. 2), however, volatility seems greater (Fig 2 & Fig. 4 — Lockdown Period 2019 (Mar 23rd -Ap 23rd) vs Lockdown 2020). There has also been an average decline in arbitrage spreads of around 5% (Fig. 4). Yet, even with this dip, the financial benefit of taking part in wholesale arbitrage remains.

Figure 1. Wholesale spot price from Epex spot.

Figure 2. Gas prices (NBP) and Wholesale power prices (Epex spot).

The potential returns, both for the day-ahead and intra-day markets, vary depending on a number of factors, including the weather (and whether it is a mild winter for example), gas prices, liquefied natural gas storage availability, and demand. For example, a stormy month will typically have a higher spread than a month with little variation in weather and gas prices.

The lockdown period has also seen a lower median spread than a typical winter. However, the range of spread is greater along with the maximum spread compared to this time last year (Fig. 4).

This could be a combination of low demand (Fig. 3) and higher than usual levels of solar for April, which was a very sunny spring. Indeed, on 20 April there was 9GW of solar PV output on the grid. This displaces higher priced generation further up the merit order, resulting in it not running.

Figure 3. Demand varies seasonally (higher in winter months than summer months), however, January 2020 is low compared to subsequent years and April 2020 is notably lower than previous years. The decrease in demand does not account for the rise in embedded generation.

In December 2019, we saw overnight day-ahead prices drop to negative for the first time too due to low demand and high wind output — something that is becoming a regular occurrence. So far in 2020 there have already been five days of negative prices on the day-ahead market, with four of these days occurring during the lockdown period.

Therefore, there remains a clear need for storage and an opportunity for arbitrage and asset owners to be paid to charge up their batteries; the charts below demonstrate this (Fig. 5).

Figure 4. Wholesale arbitrage spreads. Lockdown period refers to the period March 23rd-April 23rd.

Figure 5. Average wholesale prices for a typical day in winter, summer, lockdown and 20th April.

Ancillary services

Winning Dynamic Firm Frequency Response (DFFR) contracts continues to provide revenue certainty for asset owners, as the returns are secured for the duration of the contract.

Although the average volume weighted price for DFFR dropped slightly in recent months, there is still value in the market. For example, volume weighted average prices in April 2020 where around £7/MW/h compared to this time last year (£5/MW/h). The rebound in prices coincides with National Grids decision to move from longer term contracts to monthly and weekly contracts.

In the winter months, exceptionally high prices can be achieved by front-of-meter storage; the marginal price being set for Triad chasing hours (the weekday afternoon periods of highest demand on the grid between November and February each year). This is something we expect to continue for the next two winters.

Figure 6. Volume weighted average prices from the Dynamic Firm Frequency Response market.

Capacity Market

The Capacity Market was introduced to ensure the security of the UK’s electricity supply at when the operating margin is very low and provides payment for back-up generation when the operate margin requires it.

The recent T-3 auction — which plans ahead for capacity delivery during winter 2022/23 — went on to clear at £6.44 per kilowatt per year. However, prices are starting to rebound and the T-4 auction cleared significantly higher at £15/kW/year. This is closer to previous clearing prices of £19.4/kW for the T-4 auction for winter 2018/2019, £18/kW for winter 2019/2020 and £22.5/kW for winter 2020/21.

Another positive sign is that more unproven DSR assets are also winning contracts.


Since January 2020 the system has tended to be long more frequently than short (Fig. 8). This means that net imbalance volumes are more often negative than positive; a sign of too much generation or too little demand. The lockdown period is no exception to this trend: low demand, coupled with record levels of solar generation has led to the maximum daily system price falling, in comparison to the same time last year (Fig. 7).

This means that generators exporting into the cash-out market — for example, discharging batteries — will on average receive less than they usually would. Nevertheless, minimum prices are lower and therefore batteries can charge up at lower prices.

Figure 7. Maximum and minimum daily cash-out prices for the period March 23rd -April 20th in 2019 and 2020.

Figure 8. Net imbalance volume ratios showing a gradual increase in the proportion of time the system is long. Data from Elexon.

Distribution and Transmissions savings

Time of use distribution and transmission cost savings remain unharmed by recent events and storage assets behind-the-meter can continue to benefit from these savings.

The postponement of the implementation of the Targeted Charging Review on the demand residual from April 2021 to April 2022 offers another year of triad avoidance for behind-the-meter batteries.

The business case for storage moving forward

While coronavirus and the resulting lockdown may have had an impact on key revenue streams available to storage owners, our analysis indicates that the most significant influencing factor is weather; its impact can be seen on both demand and the proportion of the generation from renewables.

At the same time, there are some unique opportunities for storage owners to capitalise on, such as the wider spread between periods of negative pricing and high prices.

Moving forward, as renewable generation continues to increase there will be an even greater need for storage — both to balance the system in real-time and to keep the system safe when there is limited inertia. The vital role storage has to play, combined with these various revenue generating opportunities, continues to provide a viable business case for investment.

[1] Carbon Brief. Analysis: UK renewables generate more electricity than fossil fuels for first time.