By Jo -Jo Hubbard , Co-founder and CEO of Electron
It is odd to think – just three years ago – consumers were so disengaged with their energy consumption that the vast majority were not even switching suppliers to save £300. Today, with energy bills at record highs, consumers can’t switch suppliers to save £300. As a result, finding new ways to cut energy costs is rising to the top of the agenda. One such solution should be to catalyse flexibility markets.
Flexibility is when energy producers and consumers alike are incentivised to adjust their planned import or export of power to save costs and carbon. In practice this means the trading of surplus energy from renewable sources to local consumers – making the most out of renewable energy and reducing bills.
As more electric vehicles find homes on UK driveways, joined by heat pumps and solar + storage systems, increasingly engaged consumers are seeking to optimise their consumption, and therefore their bills. The result, so far, has been a commensurate doubling in the availability of Time of Use tariffs .
This is being pushed further by the government’s package for the “ biggest electricity market reform in decades ” including a proposal to enable all consumers to access “sharp” signals to consume power at cheaper, greener times of day. Now National Grid ESO is stepping in , introducing a further price incentive for consumers to charge EVs, batteries and other flexible loads overnight, when demand is low, or when sun is highest in the sky, and solar generation is abundant.
Essentially, these are all time of use incentives for flexibility. They are important for balancing intermittent renewable generation and smoothing peaks in demand to mitigate the need for new stand-by generation that would only be required for 10-30 days a year. Moreover, we already can – and do – take this same approach to consumption at commercial and industrial levels. Aggregators have packaged up and sold this type of flexibility to the grid for over a decade now.
However, when you consume is also only one part of the energy flexibility equation. The other part is where you consume.
Imagine a scenario in which Scottish wind farms are enjoying high output and generating at full capacity. At the same time London has a spike in demand. Great – London has a source of abundant renewable energy to deal with that spike, and the windfarms in Scotland have a buyer for their power. Right?
Yes, in theory. In reality, at both the transmission (long distance) and distribution (local) level, networks can become congested and no more power can flow through this part of the network.
Congestion can go both ways.
Supply congestion is when the generation that is being exported exceeds the local network capacity. Unless that generation is consumed behind the congested part of the network, it is wasted. This caused over £800 million of losses in the UK in 2020 and 2021 combined, and CO2 emissions equivalent to putting another 500 000 cars on the road.
Demand congestion is when more power is being demanded of a network than it can locally accommodate. This results in brownouts and revenue loss for businesses. The possibility of this happening also threatens the roll out of the clean technologies required for Net Zero, such as EV charging stations.
Network congestion could be solved by massive expansion and upgrades of all networks at exorbitant cost, but that’s not a realistic option. Although, some network expansion will be required, the fact is that most of the network additional capacity will not be required most of the time.
For a rapid and affordable transition to Net Zero electricity by 2035, it is vital that we minimise temporary network congestion by being smarter about paying flexible demand to consume at the right time and the right place .
What can be traded on a locational flexibility market?
The possibilities for local flexibility markets are vast.
Renewable generators in congested distribution grids might look to pay local consumers to use more power, or export less, at a certain time and location, in order to avoid curtailment and revenue loss. Essentially renewable generators would be paying to buy additional network access, but only when they need it.
An EV charging forecourt might seek to buy the right to charge more cars at once during peak charging demand from flexible local businesses.
Then there are other grid stability services, concerned with specifically maintaining the frequency and power quality of the network (rather than only matching supply and demand volumes).
Moreover, locational markets do not have to be limited to local distribution networks. Industrial hubs could also be incentivised to locate nearby larger, transmission connected renewable projects to minimise strain placed on the ultra-high voltage network. Such an arrangement could transform the unit economics of the major energy users of the future – think vertical farming, electrolysis or computationally heavy processes.
That level of innovation is exactly why a localised market-led approach is so advantageous.
Opponents of local pricing express concern over “postcode lotteries”. Indeed, why should consumers in one area have to pay more for power than consumers in another area?
This has been one of the key challenges to the concept of “nodal” pricing, in which your cost to import or export power is determined by where you are connected in the grid.
Nodal pricing is certainly one way of implementing local prices. However, nodal pricing is a centralised approach to establishing locational value. It requires the operator in charge to set the price of using the grid at a particular time and particular location. Moreover, the extent to which this pricing would reach into the distribution grid remains to be decided.
We propose a symbiotic but different approach: locational incentives for flexibility (e.g. temporarily buying or selling additional access to the grid) and not power .
In this approach, pricing would be upside only (i.e. no surcharges for the locationally challenged). This makes sense since the flexible actions of consumers in one congested area of the grid help to save network reinforcement costs and renewable wastage for all consumers. Moreover, these local payments, in turn, encourage investment in flexibility exactly where it is needed.
We believe that local flexibility markets could and should empower people and businesses to take their ideas and run, to become price makers as well as price takers. They will be critical in allowing energy market participants to coordinate profitably.
Where does this all lead?
Flexibility was of little relevance in the old-world, where almost all of our energy came from coal and gas, which was connected at on a national level grid, and was available to turn up or down demand.
In that world, it made sense to charge consumers based on total MWhs consumed. It makes less sense that this form of billing persists today for many when over 40 per cent of our power is produced by renewables at zero marginal cost. Indeed, generation is increasingly often surplus to demand.
As we transition to around 80 per cent renewable generation, the unit cost of producing power falls rapidly, we will often have a surplus of supply to demand; and time and place become the key limiting factors.
It is no exaggeration to say that we could reach a point where when and where energy is used will be a bigger factor in pricing than how much energy is used. In other words: flexibility markets tomorrow could be worth more than energy markets as we understand them today.