Scotland has an increasing share of GB’s renewable power generation, while demand is concentrated in England. Unfortunately, there is a major long-standing transmission constraint between the two countries and grid congestion remains endemic.

In the wake of the energy price crisis, the UK government initiated the Review of Electricity Market Arrangements (REMA). One of the outstanding issues it considers is whether to retain a single wholesale electricity price in Great Britain, or move to zonal wholesale pricing.

This issue now seems unlikely to be resolved before the next General Election.

Competitive evolution

The roots of the issue go back to privatisation, in 1989-90. In Scotland, privatisation essentially preserved two vertically integrated companies: Scottish Power and Scottish Hydro-Electric (the predecessor to today’s SSE).

Reforms initially confined the competitive wholesale market to England and Wales.

Scotland has extraordinary renewable potential, but the grid has struggled to deliver power to demand. — *National Grid*

New Electricity Trading Arrangements (NETA) were introduced in 2001. Following this, policy makers and regulators became concerned on two fronts.

First, Scottish consumers had not benefited to the same extent as those elsewhere in Britain from a substantial fall in wholesale electricity prices. Second, as renewable generation in Scotland began to grow, it would require access to a more transparent and liquid wholesale electricity market.

These concerns led to the introduction of the new British Electricity Trading and Transmission Arrangements (known as BETTA) in 2005.

The Electricity System Operator (ESO), which already existed within National Grid, evolved from covering England and Wales to covering the whole of GB. Furthermore, the previously separate electricity markets were integrated, despite the north-south transmission constraint.

This created a single wholesale electricity price for the whole of GB.

In the meantime, Scottish renewable generation continued to grow rapidly. Scotland provided suitable conditions for onshore wind farms, followed later by the development of offshore wind generation. In addition to a better wind resource, Scotland had fewer planning constraints than those faced by developers in England.

Managing

This growth was also facilitated from 2010 by an approach known as “Connect and Manage”. This sought to accelerate grid connections for transmission-connected renewable generation projects. The responsibility for “managing” a constrained grid fell largely to the ESO.

*Source: Historic Regional Statistics and Department for Energy Security and Net Zero Energy Trends*

Total electricity generation in Scotland has been broadly flat over a period of almost 20 years. The growth in renewables has offset a sharp decline in thermal generation, such as the closure of legacy coal-fired power stations in the south of Scotland.

From 22.7 TWh as recently as 2009, Scottish electricity generation from fossil fuels had fallen to 5.0 TWh by 2017. It has no remaining coal generation at all.

Over the same period, electricity consumption in Scotland has steadily declined – in part due to improved energy efficiency. Also playing a part in this reduction has been the closure of energy-intensive heavy industries, such as steel and aluminium.

By 2022, annual Scottish renewable generation was around 13% more than the total amount of electricity consumed in the country.

Unsurprisingly, the result has been a massive increase in net electricity transfers from Scotland to England. Net transfers reached as much as 19 TWh in 2022, more than three times the level recorded in 2004.

Long-term programme

There have been major investments in grid reinforcement over the years, but these have simply failed to keep pace with the rising level of electricity exports from Scotland.

The onshore Beauly-Denny transmission line went live in 2015, with around 1.2 GW of capacity. This 220-km link, which is within Scotland, passes through areas of natural beauty. As a result, it took many years of planning and delivery to build out the grid.

This experience led the industry to look at ways of reducing the transmission constraint, independent of onshore planning and approval delays.

A move to build offshore is one such response. The 2.25 GW Western Link was completed in June 2019, between Scotland and North Wales. It cost around £1.2 billion and was two years overdue.

These major investments failed to overcome the growing constraint issue. Accordingly, two further offshore grid connections of 2 GW each are now in active development on the eastern side of the country.

The Eastern Green Link 1 will run between Torness and County Durham. Construction is slated to begin in 2025 with a view to being onstream in 2029.

Meanwhile, the Eastern Green Link 2 will run for 500 km, between northeast Scotland and Yorkshire. Ofgem recently announced that it will receive £3.4bn in funding.

There are more such plans afoot. National Grid recently published plans for Eastern Green Links 3 and 4.

Other market consequences

There are a number of consequences from this constraint issue.

The first of these is the pattern of Transmission Network Use-of-System (TNUoS) charges. These are mainly paid by transmission-connected generators to cover the costs of installing and maintaining the electricity transmission system.

These are geographically based and are intended to reflect the system costs imposed by different generators, as well as incentivising new projects to move to generation deficit areas, such as southwest England.

In 2022-23, for example, TNUoS charges for renewable generation varied from over £25 per kW in the north of Scotland to negative charges in much of southern and southwest England.

This disparity is a constant source of grief among Scottish generators. National Grid would no doubt say, though, that these charges reflect the high cost of investing to transport electricity southwards.

Despite various TNUoS reforms over the years, these charges remain volatile from year to year. As such, this creates material uncertainty for generators, especially Scottish renewables.

Demand costs

A second consequence is the high cost to National Grid of managing constraints, recovered as part of Balancing Service Use-of-System (BSUoS) charges.

Until recently, it recovered these costs from generators and customers. They have now switched wholly to demand. In effect, therefore, these high and rising costs fall on electricity consumers across Britain. These are shown by the grey bars in the following chart:

Source: National Grid ESO, Balancing Cost Strategy document

A third consequence has been the growing curtailment rates for renewable generation, especially Scottish wind farms.

In 2022, for example, 4% of GB wind generation was wasted due to grid congestion – 3.4TWh. This is equivalent to the yearly consumption of 1 million British households.

The REMA document, released in March, highlighted this growing curtailment concern. It cost £700 million in 2018-19, rising to £1.8bn in 2022-23. REMA said that a three-year delay in network construction could drive up curtailment costs to around £8bn in the late 2020s.

Finally, there is little incentive under the current market arrangements for new energy-intensive businesses (such as data centres) to locate in Scotland and thus boost national electricity demand.

The impact of REMA

Unless there are market changes, the fundamentals will remain the same. National Grid’s response has been to plan out a series of expensive offshore transmission links between Scotland and England.

REMA dismissed the concept of hyper-local nodal pricing. However, it kept the door open for zonal pricing. Other countries do use such a model, such as Scandinavia and Italy.

Afry, in mid-2023, forecast Scotland’s wholesale electricity prices might be £9 per MWh, in 2021 prices, below those in southern England.

It went on to forecast the price differential would narrow to £3-4 per MWh by 2035.

Locational pricing might be able to attract more demand north of the border, in Scotland, although Scottish generators would suffer. For instance, energy-intensive data centres could locate to Scotland, while some offshore wind farms might opt for a transmission landing point in England.

Who can move?

Overall, demand is likely to be more responsive to locational price signals than most new generation and energy storage assets. At least some of the transmission constraint burden would be addressed via the price mechanism. This could reduce the need for investment in high-cost transmission links.

Among generators, the reaction to a zonal pricing policy option has mostly been sceptical.

Their main argument is that a fundamental change like this would increase risk and create investment uncertainty at a time when cost of capital and timely low-carbon investment are of the essence. There is also a risk that traded wholesale market liquidity could be further weakened – and that it is already much less robust than five years ago.

In turn, one could reasonably ask whether there is a simpler, alternative way to generate some of the helpful commercial incentives that zonal pricing is likely to create.

Complete reliance on centrally planned grid investments – however much they are needed – is likely to be a high-cost remedy. It will also take time to take full effect. There is plenty of evidence to show that properly designed market price incentives do work, if given the opportunity to do so.

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