Fixing energy markets from the ground up

With the government now mulling over the responses to its consultation on electricity market reforms, Electron co-founder and chief executive Jo-Jo Hubbard speaks to Utility Week about her concern that not enough emphasis is being placed on local energy markets, where the biggest gains are on offer. 

“It’s leaking from the roof and it’s leaking from the basement,” says Hubbard, explaining her concerns over electricity markets as they currently stand. In her analogy of a house in a state of disrepair, the energy system is leaking out value from top to bottom.

She worries that the government’s Review of Electricity Market Arrangements (REMA), which closed to responses in the autumn, is primarily focused on the “top-down” optimisation of the energy system – fixing the roof: “But the problem is how you build the foundations is really fundamental to what kind of roof you can support. And if you just fix the roof and you don’t fix the foundations, you’re going to keep letting in water.”

Hubbard founded Electron in 2015 to create of the kind of local peer-to-peer energy markets that can capture some of this lost value, enabling parties on both the generation and demand sides to make the best use of their assets and the power grid they share.

Since then, the company has partnered with various organisations, including suppliers, generators and network operators, to trial local energy markets around the country. For example, Project TraDER in Orkney, which ran from late 2019 to spring 2021, allowed renewable generators on the islands to trade with local sources of demand to absorb their excess power, thereby avoiding network constraints and the resulting curtailment.

However, Electron’s work thus far has been limited to innovation projects; as of yet, none of these types of markets are being operated as part of business as usual.

Hubbard separates flexibility markets into three strata: the “top-down” markets of the National Grid Electricity System Operator (ESO); the “middle-down” markets of distribution network operators (DNOs) who are taking on the new role of distribution system operator (DSO); and the “bottom-up” markets of peer-to-peer trading between distributed energy resources (DER).

She acknowledges the benefits of both top and middle-down optimisation of the energy system, welcoming the possibility of either zonal or nodal locational wholesale prices as mooted in the REMA consultation and advocated for by organisations including the ESO, Octopus Energy and the Energy Systems Catapult.

But Hubbard says the biggest gains will be found from bottom-up optimisation on local distribution networks, where around a third of generation and the great majority demand is connected to the power grid.

With the rollout of low-carbon technologies such as electric vehicles, heat pumps and renewable generation, these networks will become increasingly congested.  She says the trading of network capacity at these levels is going to be “one of the biggest, most valuable forms of flexibility anywhere.”

Hubbard gives three examples of the kinds of trades she is talking about, the first being renewable generators with flexible connections seeking to avoid curtailment.

Flexible connections allow generators (and consumers) to connect to constrained areas of network more quickly and cheaply than would be possible with a firm connection, which would require network reinforcement at the cost of both time and money.

In exchange, they are subject to curtailment by DNOs, for example at particular times, using active network management systems.

Hubbard says there are already around 2GW of flexible connections in Britain and with Ofgem’s reforms to network access arrangements, due to take effect from April 2023, they will start to become the norm.

Unlike transmission-connected generators, which are paid by the ESO through the Balancing Mechanism to limit their output: “If you are connected to the distribution level and you’re curtailed, you, as a renewable investor, lose all that revenue that that you would have made by generating.”

Local energy markets can allow generators to avoid this curtailment by buying supplementary grid access rights from other network users beneath the same point of constraint, which can be paid to lower their output or increase their consumption: “If you do that you make more money by being able to export more power. And consumers make more money by being paid to soak up your excess power, for example. It’s a win-win.”

Hubbard says Electron is facilitating this type of trading as part of the £8.4 million BiTraDER project led by Electricity North West, which began in March of this year.

“We’re getting a signal from the active network management system saying turn off your windfarm. We’re getting a price from the wind farm that they’d pay to stay online. That price and volume is then going live at the point where the active network management system is saying turn off and local multiple aggregators can be matched this with this price, and do demand turn-up, for example, to help create space on the network to bring the wind farm back online.”

The second example she gives is of an electric vehicle chargepoint operator facing a long wait to get the size of grid connection they would ideally like. In this instance, the operator could opt for a much smaller connection in terms of firm capacity, but then buy extra grid access rights during on the fly or during peak charging hours, paying other network users to reduce their demand beneath the relevant constraint.

In theory, Hubbard says they could even have a firm connection of nil: “You could plug your battery straight into the grid but you don’t have the right to use the grid unless you buy it. It’s a whole different concept. Instead of having a fixed grid capacity, you’ve got a market based grid capacity and it’s a whole different product.”

Taking things a step further, she gives the third example of an industrial or municipal zone being given a capacity limit beneath a network node and then allowed to optimise how this capacity is used. Parties operating in these zones could trade freely between each other and together in aggregate with other network users.

“That’s completely innovation. That’s one step further on decentralisation. That’s the DNOs saying here are your limits and you handle it behind the limit.”

“We’re moving away from this world where you just get dumb access to push or pull whenever you need from the grid and towards a world where everyone has to use it a bit more thoughtfully and economically,” she adds.

Hubbard says the absence of these kinds of markets is leaving lots of flexibility on the table, particularly as many potential providers are “not really willing to commit to six-month bilateral capacity obligations” through DNOs’ flexibility tenders.

“They need something a bit more dynamic; a bit more opt in and then opt out. And they also need to know that those markets that they’re investing in hardware and dispatch equipment to go and be part of are going to endure. It’s not enough to have all these different experiments and innovation markets.”

The government’s REMA consultation did discuss local energy markets, for instance, raising the possibility of creating markets equivalent to the current national market at each point of connection between the transmission and distribution network.

But Hubbard is concerned that too little attention is being paid to the kind of local energy markets she wants to see – primarily focused on trading network capacity – which could end up taking a back seat to reforms of energy markets at higher levels such as severing the link between fossil fuel and renewable power prices or introducing locational wholesale prices.

In the case of the latter, Hubbard says zonal or nodal locational pricing could work well alongside local energy markets: “If you think of local markets as a different vector for aggregation – it’s regional aggregation instead of aggregation by whoever happens to be your aggregator or supplier – then they are obviously going to end up with a net import or export and a price at which they can adjust that, because that’s what flexibility markets give you.

“A nodal market implemented sensitively like that could be a fantastic accelerator of scaling these markets.”

But she does not believe locational power pricing can be extended all the way down to the lowest voltage levels due to a lack of liquidity that would leave markets open to gaming.

In general, she fears that local flexibility will end up being “pulled into the national market without thinking about the local market,” saying truly local optimisation of the energy system is “a real blind spot” for the industry.

She worries that for a battery operator, for example, there will be a divide between local and national markets that mean “both markets are half as valuable.”

Done poorly, Hubbard says the government’s market reforms could create “confusion as to whose job it is to optimise at a local level” or require that “everyone, even distribution connected assets, pool into some larger locational market that doesn’t take into account local network constraints.

“If you’re at a local level you’ve got to have some say as to how your network capacity is prioritised, even if you can’t control when and where the DNOs makes all the relevant upgrades.”

“The anxiety at the moment is it feels like the two conversations are being explicitly separated,” she adds.