Managing an electricity system is not just about balancing supply and demand. Since electricity must be physically transmitted from the generation source to wherever the demand is, location plays a huge role. ‘Transmission constraints’ is an umbrella term, which describes the physical factors that limit the ability to transmit power from one region to another. Each constraint on the transmission system needs to be managed - and that comes at a cost.
In this article, we look at:
- Transmission boundaries in Great Britain.
- The types of constraints that occur across these boundaries.
- How the cost of managing constraints has changed over time.
- The factors that influence constraint costs.
Spoiler alert
- We’ve taken data from six transmission boundaries. These reflect the main routes that power travels across in Great Britain.
- Transmission constraint costs come from managing the risks of ‘largest loss’, system inertia, voltage, and heat.
- Long-term, the costs of managing constraints are expected to rise, due to increasing renewables penetration. However, there has been a steeper-than-expected, short-term increase - due to recent high energy costs.
The impact of location on constraint management
At certain locations, power flow is concentrated as it travels through large, high-voltage cables. These locations form ‘boundaries’. At these boundaries, flow can be constrained - due to the physical properties of the system.
In this article, we focus on the six boundaries shown in figure 1 (below).
- The six boundaries are: SSE-SP and SCOTEX in Scotland; SSHARN in the north of England; SWALEX across South Wales; and ESTEX and SEIMP in South Eastern England.
- Each of these boundaries has a limit on how much power can flow across them. This is essentially dictated by the size of the copper cable at each.
- These limits can lead to constrained power flows across the boundaries.
When a transmission constraint occurs, National Grid ESO uses the Balancing Mechanism to manage output. This maintains system stability. A mirrored action on the other side of the constraint balances demand with supply. Affected generators are compensated for their services via system-flagged Bid-Offer Acceptances in the Balancing Mechanism.
Case study: SSE-SP boundary (February 2022)
In the first week of February 2022, Scottish wind generation averaged 3.9 GW. (This put it in the top 2% of wind production weeks since January 2018.) These unusually high levels of wind generation put considerable pressure on the SSE-SP and SCOTEX boundaries.
- The thermal constraint limit of the SSE-SP boundary was 2.5 GW - and there was 2.3 GW of power flowing South across it. This meant that utilization exceeded 91%.
- During this period, National Grid ESO spent around £4m per day managing thermal constraints across the SSE-SP boundary.
- The SCOTEX boundary saw flows of 3.9 GW in the same time frame - a utilization rate of 89%.
- National Grid ESO spent around £1.3m per day across the SCOTEX boundary.
- At each boundary, these costs were considerably higher than usual. Figure 2 (below) shows the daily average cost of constraint management, at these two boundaries, by frequency.
Transmission constraint categories
National Grid ESO breaks down transmission constraint management into four categories:
- Largest loss - this occurs when the ESO believes that it is too reliant on a particular generator. Essentially, the export power of any given generator must be below the ability of frequency response services to manage its potential loss.
Imagine that Generator X is scheduled to be the largest exporter of power onto the grid during a given settlement period. The export power of Generator X is above the volume of procured frequency response that can handle a trip. Therefore, the ESO will turn down Generator X in the Balancing Mechanism - and turn up some other generators to balance this out - in order to reduce the risk of one big outage causing excessive damage. - System inertia - this occurs when the ESO believes there is not enough inertia on the grid. Therefore, it increases the output of a thermal generator - with inertia-producing, rotational mass - in the Balancing Mechanism, to help manage grid frequency.
You can read more about system inertia here. - Voltage constraints - this means instructing an asset to import or export power to manage system voltage.
See our piece on reactive power for more details. - Thermal constraints - this means instructing an asset to import or export power to manage power capacity limits.
Constraint management costs
Figure 3 (below) shows the cost of managing constraints across the six boundaries outlined in this article, from April 2017 to September 2022.
- The impact of recent gas price hikes can be seen in the difference in costs from the year ending September 2021, and those from the year ending September 2022. From October 2020 to September 2021, the ESO spent £0.76b managing transmission constraints. From October 2021 to September 2022, it spent £2.0b. This represents a 165% year-on-year increase in costs.
- Also, costs associated with managing constraints have increased significantly in the last five years - as more distributed renewable generation has come online.
Constraint management volumes
Figure 4 (below) shows the volumes (GWh) procured by National Grid ESO to manage constraints across the six boundaries outlined in this article, from April 2017 to September 2022.
- During the COVID-19 lockdown, procured volumes - in terms of both turn-up and turn-down - rose dramatically. This was due to low demand.
- Over 10 GWh of system inertia was procured in May 2020, to combat the reduction in fossil fuel generation.
- Low demand also led to reduced transmission losses. To combat this, National Grid ESO had to turn up generation to manage voltage issues, and turn down generation to mitigate for largest loss.
- Overall, thermal constraint management has made up the bulk of the procured volumes since November 2021. Generators are being turned down, so that cables don’t overload (which can cause them to heat up and possibly fail). Despite total constraint management volumes decreasing (compared to those during the pandemic), constraint costs have skyrocketed. This is due to the impact of rising gas prices. (See figure 3.)
Even with significant network reinforcements, National Grid ESO predicts that constraint costs will rise to an average of £3b/year by 2034 (according to their NOA 7 Leading The Way scenario). Market reform may be needed to enable more efficient dispatch of assets - with co-optimization for constraints being considered as part of the Review of Electricity Market Arrangements.
Key takeaways
As renewables make up a larger proportion of Great Britain’s energy stack, the challenges of managing and maintaining a reliable transmission network increase. Constraint management costs have risen over the last few years. However, market forces also play a significant role: there has been a dramatic rise in costs recently due to high gas and electricity prices.
To manage constraints in the future, significant network reinforcements will be needed, as well as improved dispatch mechanisms that better incorporate potential constraints into price signals.