Is it possible to decarbonise electricity without destroying the power market? Demand may hold the answer.

Conventional wisdom tends to present full grid decarbonisation and electricity market stability as mutually exclusive objectives. But new research from Germany and new regulations in the UK suggest there is a way for the Labour government to have its ‘clean power’ cake and eat it, so to speak.

The renewables problem is well understood. Wholesale power prices crash when cheap wind and solar flood the grid, then spike when weather-dependent generation drops away. As more renewables connect, binary pricing ensues: long periods of low or negative prices, followed by short bursts of impossibly high scarcity pricing.

This situation could render the energy market uninvestable for renewables generators, storage assets and dispatchable plant alike. It would ultimately limit the integration of intermittent renewables and thwart efforts to decarbonise the grid fully.

But it doesn’t have to be this way.

The value of switching off

Enter demand flexibility: the ability to dial big chunks of demand up and down in response to non-dispatchable power sources. Often this is achieved by paying large consumers, or an aggregated group of smaller consumers, to switch on or off in response to wholesale price signals.

The so-called “time-shifting” of consumption to match variations in supply could avert the binary pricing paradigm. In doing so, it would prevent the energy market from collapsing under a wave of zero marginal cost wind and solar generation.

That’s according to new research from the Technical University of Berlin. It found that demand flexibility could play a key role in stabilising electricity prices in a renewables-dominated system.

The paper, Price formation without fuel costs: the interaction of elastic demand with storage bidding, modelled an expansion of Germany’s power mix with “more realistic demand behaviour” that better reflects the amount of demand elasticity already offered by industrial consumers today.

Avoiding market collapse

“Studies looking at electricity market designs for very high shares of wind and solar often conclude that the energy-only market will break down. Without fuel costs, it is said that there is nothing to set prices,” authors Tom Brown and Fabian Neumann said.

Symptoms of breakdown include long phases of zero prices whipsawing up to scarcity prices too high to be politically acceptable; low energy market prices preventing cost recovery; high variability of revenue between different weather years; and difficulty operating long-term storage with limited foresight.

“We argue that all these problems are an artefact of modeling with perfectly inelastic demand,” they said. “If short-term elasticity to reflect today’s flexible demand (-5%) is implemented in the model, these problems are significantly reduced. Prices no longer jump between zero and scarcity; they remain stable over many weather years and do not collapse with small capacity perturbations.”

Testing the waters of demand flex

Demand flexibility, also known as demand side response (DSR), is not new. In Great Britain’s power market, DSR is already making a modest contribution to system balancing.

The amount of savings is small but starting to grow. Initial trials have gathered valuable real-world data that’s helping the energy system operator understand how to improve and expand the contribution of DSR.

National Grid ESO trialled a new flexibility market explicit aimed at households in winter 2022-23. The Demand Flexibility Service (DFS) paid households and small businesses to reduce their energy demand during peak periods to help balance the electricity system.

A total energy reduction of 3.3 GWh was achieved during the first trial over November 2022 to March 2023. A second trial over the same period, in winter 2023-24, delivered 3.7 GWh of savings over 14 test events. Of these, it carried out seven under competitive conditions.

Bids as low as £150 per MWh were submitted and the average clearing price was £1110.9 per MWh. In total, the DFS tests cost £11.9 million. The maximum volume delivered in any half-hour period rose to 410 MW – an increase of more than 50% compared to the previous winter.

Consumers with smart meters participated via their energy suppliers, receiving rebates on their energy bills. In total, 2.6 million smart meters subscribed, 99% of which were at domestic properties.

Post-trial surveys found that many participants felt the reward of £1 to £5 was too low to make it worthwhile changing their routines. Others said it was tricky to remember when flexibility periods were taking place, or to understand what their electricity demand would have been had they not provided demand side response – so-called “baselining”. These concerns are being addressed in future iterations of the DFS.

Aggregation: power in numbers

Octopus Energy has been leading the charge on demand flexibility in the UK for the last few years, being the first large utility to work with the ESO on the first DFS trial in the UK. Since then, Octopus has launched its own scheme – Saving Sessions – which forms part of the DFS.

“Just looking at this previous winter alone, the scheme has been a huge success for engaging customers to help balance the grid, and give customers money back for making small tweaks to their energy usage,” a spokesperson told E-FWD.

Octopus recorded 1.8 million sign-ups – more than three times more than the next largest, British Gas, with 500,000 – and paid out £10.5 million to customers for saving on aggregate 3.8 GWh. Octopus said this saved 64 tonnes of CO2 by avoiding the need to fire up gas or coal plants to meet residual demand.

The company also claims to operate “the UK’s largest and the world’s only virtual power plant” via Intelligent Octopus Go. This is its most popular electric vehicle (EV) tariff. The platform manages more than 150,000 EV battery chargers and other domestic devices with an aggregate capacity of 1 GW.

Looking further ahead, VPPs such as Intelligent Octopus Go will make the greatest flexibility contribution via vehicle-to-grid (V2G) – technology that allows EVs to discharge into the grid at times of peak pricing. While the infrastructure needed to enable this is still at the earliest phases of rollout, V2G could overtake smart charging to become the single largest source of system flexibility in the late 2030s, according to the ESO.

*The growth outlook for flexibility in one of National Grid ESO’s three pathways to net zero. Source: ESO Future Energy Scenarios*

Can big industrials flex too?

Demand-side VPPs provide a route to flexibility markets for large numbers of smaller consumers. But what about the other end of the spectrum: large industrial consumers and big corporate power users, such as data centres?

In Britain, after reforms over the last decade or so, corporate customers can participate in the balancing mechanism, the capacity market, ancillary services, and distribution constraint management. They can do this directly or by working through the aggregator of their choice.

But there has been one piece missing. “Customers could only offer their flexibility in the wholesale markets through their retail energy supplier,” said Paul Troughton, senior director of regulatory affairs at Enel X – the energy management services arm of Italian utility Enel Group.

That’s about to change thanks to an incoming change to regulator Ofgem’s Balancing and Settlement Code (BSC). The P415 modification, as it’s known, was proposed by Enel X in 2020 and approved by Ofgem last October. Elexon, the company that runs the UK electricity market, is now implementing the necessary system changes ahead of go-live in November this year.

Commercial and industrial energy users can already provide valuable flexibility to the power system. However, in the balancing mechanism (BM) – where Demand Flexibility Service resides – they are dependent on the ESO’s dispatch decisions, where they can often be overlooked (or ‘skipped’).

“By offering their flexibility in the wholesale market, customers can lock in value without such risks,” Troughton said.

Virtual trading

Modification P415 enables businesses to do just that. They can access the GB wholesale electricity market and trade flexibility through aggregators, also known as Virtual Trading Parties (VTPs).

Customers will be able to maintain their usual consumption through their existing supplier, under the same retail supply contract and pricing. If they can offer flexibility beyond those “normal” consumption patterns they can be paid for that via their VTP. The greatest revenues are available for demand reduction during periods of high wholesale prices.

“The mechanics of participating in the wholesale market under P415 mirror those of the balancing mechanism, but with less immediacy required. This makes wholesale market participation ideal for businesses needing more time to power down large-scale processes.

“Businesses capable of participating in BM or the capacity market are not excluded, making the wholesale market a vital component of the full stack of market participation, maximising energy flexibility value,” the Enel X director said.

Seizing the opportunity

Projections from Aurora Energy Research indicate that value gained via flexibility will shift from the balancing mechanism to the wholesale market over the next decade. This shift is attributed to increased power system volatility due to greater renewable penetration.

“As the UK power system continues its transition, pricing is likely to become more volatile,” Troughton added. “Although volatility is often seen as a problem which drives up costs, it brings opportunities for energy users who can be flexible. Enel X is supporting businesses to explore their potential flexibility, and get value from offering it in all the available markets.”

Commercial and industrial businesses across diverse sectors will benefit from the code change but “will likely need the expertise of experienced aggregators to fully capitalise on the revenue opportunities”. With wholesale market participation, energy users “gain significant control” by deciding “when and how often to participate, selecting attractive prices, and choosing their aggregator partners,” he concluded.

Related Content

UK’s strategic energy plan banks on hydrogen storage