Where did the GB market come from? The single power market dates back to 2005, when the British Electricity Trading and Transmission Arrangements (BETTA) allowed buyers and sellers in Great Britain to trade in a market across England, Wales and Scotland for the first time.

When BETTA was introduced, energy regulator Ofgem explained that: ‘Scottish customers are not benefitting from the competition which is now established in the wholesale market in England and Wales’ (referring to a previous reform that introduced direct contracts between buyers and sellers). The regulator said Scottish generators would be able to sell their electricity to customers in England and Wales (because, then as now, Scotland produced more electricity than it needed). In addition, BETTA would allow ‘more competitors to enter the Scottish wholesale and retail markets, which will put even more pressure on prices to the benefit of consumers and businesses’.

BETTA fulfilled the important aim of creating liquidity in the power market. More generators selling power and more retailers buying it would both increase competition to drive the price down, and provide a route to market for new participants, who now had more potential counterparties.

But behind the single price is the reality that costs in generating and moving electricity from one part of the country to another varies hugely. Closer is cheaper and congestion arises if there are limited transport links between sender and recipient.

Congestion was of little concern to the electricity sector at the time BETTA came in, because most of our power was generated at large central fossil fuel plants and the electricity network had been built around this. Now we take advantage of different resources to generate power, such as large wind farms offshore of Scotland, or interconnectors with our European neighbours. Flows far exceed capacity in places and we cannot manage this without new transmission lines.

What is more, until the new network is built – a process that has previously taken a decade or more – the National Energy System Operator (NESO) has a ‘redispatch’ problem. That is because electricity cannot be delivered the next day or left with a neighbour. It has to be ‘balanced’, second by second, and in every place. To do that, NESO translates the deals made in the wholesale market to reality. Each half-hour throughout the day it manages a so-called ‘balancing market’, by which it ensures electrons reach customers and that grid network frequency and voltage are stable. Where the wires are too congested for power to flow as contracted ahead of time, NESO has to ‘redispatch’ – pay power plants in one location to turn down and contract new generation elsewhere in its stead. Both costs are paid by customers.  

Because the generators and customers have changed, but the network has not, what was previously a small balancing adjustment is now a significant part of the entire market.

Behind the single price is the reality that costs in generating and moving electricity from one part of the country to another varies hugely. Closer is cheaper and congestion arises if there are limited transport links between sender and recipient.

Solving the problem
Clearly one way of solving this problem is building new power lines. Recently dubbed the ‘Great Grid Upgrade’, this is now a major initiative in Great Britain.

It would also be more efficient for market participants to use power generated close to them, but how can this be achieved? One solution is to split the market up, typically using congested areas as boundaries, and allow different prices to be set in different zones. The key question debated by the industry now is whether this change from the single price to zonal pricing is necessary or desirable.

There are a number of issues to be considered. 

• Customers in zones where there is excess generation should benefit, because their prices will fall. Elsewhere, customers will lose, because in areas where there is a shortfall, prices will rise. 
• The price differential will incentivise new connections between the zones, eventually reducing NESO’s balancing and redispatch costs. But new network is slow to build. What is more, experience from elsewhere (see below) indicates that customers in low price zones may resent such trades. 
• Eventually, electricity price may be a factor in companies’ decisions on where to locate, reducing transport costs.
• Some zones may not contain any gas-fired power generation. Gas is often the ‘marginal’ option across the current GB market and, as such, it is influential in setting the price. That hit GB customers particularly hard during the energy crisis, when gas prices leapt up. Having areas where gas does not set the price could help break that link and reduce prices overall.
• Zone boundaries typically follow network constraints, but those areas will change when new networks are built. We could disrupt the industry by setting up zones, only to disrupt it again a few years later by changing the boundaries.
• Electrification of the economy, already happening across transport, industry and heat, will change electricity flows.
• Liquidity – one of the reasons why Ofgem brought in the single market – may be reduced under zonal pricing schemes. Zones will have less competition, and there may not always be a buyer for power produced.  

Zoning overseas 
Great Britain’s market is not alone in facing this problem. Some countries have positioned themselves at the opposite extreme and allow for a different price to arise at thousands of ‘nodes’ in the network (an approach which was considered, but ruled out, in GB). This gives price signals to both generators and customers. For example, US utility Dominion Energy serves an area in northern parts of the state of Virginia. The Grid Status blog highlighted two substations in the region that are located next to each other geographically, but appear at very different points in the electricity network. The result: they ‘experience vastly different pricing’.

By contrast, other countries have always maintained a zonal approach. For example, Norway is split into five zones; Sweden has four and Denmark has two. Europe’s association of power grid operators (Entso-e) recently said Germany should ‘consider splitting its electricity market into up to five price zones to better reflect the different costs across the country’. It has a similar problem to Great Britain, in that the customers for the power generated by gigawatt-scale wind farms in the North and Baltic Sea are the large industrial conglomerates in the south, previously served by fossil fuel plants. New transmission lines are required to connect them.  

Norway’s transmission network operator Stattnett says the country has zones because: ‘In a weather-based power system like Norway’s, the power situation will vary between different parts of the country, and there is not enough capacity in the power grid to equalise the differences in all situations.’

As zones are linked, trading tends to lead prices to converge, but this is naturally less popular in the zone where the price moves upwards. This is even more in question when the price rises to meet the needs of people further away. An interconnector between Norway and Great Britain has its Norwegian terminal in Kvilldal, Suldal, an area where hydropower is relatively abundant and prices relatively low. Producers in Norway can sell their power to Great Britain whenever GB prices are higher than local prices. But for local customers it means that prices rise, and that has caused some Norwegian politicians to promise to limit power exports.

A changing system
The mismatch between resources and wires is not the only consequence of our changing electricity system. Electrification of heat and transport is increasing the need for electricity, and changing where it is used. So are other aspects of our lifestyle.

Dominion Energy (above) is an example. One area of its network has come to be known as ‘data centre alley’, where over 100 data centres have been connected since 2019. Peak load in the area is expected to increase from 18 GW in 2015 to 47 GW by 2039. Transmission upgrades are due in 2027, but the Grid Status newsletter said ‘in the short to mid-term, large new data centre loads should look to locate elsewhere’.

Other changes are beginning to affect flows. In the centralised generation system, power flowed from centralised power stations to businesses and homes. Now, however, there is a huge amount of distributed generation feeding consumers directly. By avoiding use of the transmission network, this reduces costs. But it affects system operation in two ways. First, it means that sometimes, especially on a day of wind and sun, load on the transmission network drops very low and NESO has fewer options in redispatch. Second, in some areas there may be occasionally an excess of energy that is exported ‘up’ to the transmission network, affecting how that is managed.

What’s the way forward?
Opinions are divided on whether the government should make a change to zonal pricing. The costs and benefits look different depending on the user’s assumptions, geographical location and role in the industry.

There is a price to be paid to make the change. Legal agreements abound between thousands of parties in the industry for everything from ground leases to power purchases. The professional fees charged to examine how such agreements would be affected by a switch to zonal charging will run into millions.

Not deciding also has a cost. Part of attracting companies to do business or invest is reasonable certainty that investment frameworks will not be arbitrarily changed. The government deals with this by ‘grandfathering’ mechanisms until the end of their promised term, even when they are superseded. The UK has a good reputation for keeping its promises in this way, which cuts the cost for everybody. So whether or not the charging basis changes for the future, some of the current costs are baked in.

The House of Lords Industry and Regulators Select Committee took evidence from both sides of the debate and came out in support of zonal charging in a report published on 3 June.

A paper for the UK Energy Research Centre (UKERC) by Will Blyth, Callum MacIver and Rob Gross argues for a middle way. They say that zonal charging will only work successfully once we have completed our grid expansion plan, because ‘grid build-out would create unstable and unpredictable commercial relationships between zones’.

The decision lies with the Department for Energy Security and Net Zero, (DESNZ) as just one of a package of measures that will follow a wide-ranging Review of Electricity Market Arrangements. No outcome will satisfy everyone.

• Further reading: ‘Zonal pricing should lower the cost of UK electricity by encouraging generators and consumers to come together – report’. Following an inquiry into energy grid and grid connections, the UK Parliament’s House of Lords Industry and Regulators Committee suggests that regional zonal pricing should enable better use of existing grid capacity and lower the cost of electricity, provided that the transition and its risks are managed well. Chair of the 12-member Select Committee is Baroness Taylor of Bolton.
• The introduction of zonal electricity pricing should come after the transmission grid has been upgraded to deal with a future zero carbon electricity system, argue Will Blyth, from Oxford Energy Associates and Callum MacIver, from Strathclyde University; both also work at the UK Energy Research Centre (UKERC).