Why does intermittency come with a cost?
Many nations want to decarbonise their energy systems and start using fewer fossil fuels and more renewable energy. However, the renewable output from intermittent assets (like wind and solar) is less reliable and flexible than the power that thermal generators provide as standard.
There’s no storage technology currently available that’s capable of supporting a national grid more reliant than ever upon natural sources of renewable electricity. The peaks and troughs between windy or sunny days, weeks, or months are simply too long. Without such storage capacity on hand, it’s impossible to continuously match renewable generation and usage – as all grids must do. This means the system becomes incapable, without back-up, of providing power whenever and wherever it’s needed.
To counter this, the Electricity System Operator (ESO) must balance supply and demand. Failing to do so can result in grid instability and even blackouts. The ESO can fine-tune supply by collaborating with generators to turn their power on, up, down or off. Or, it can influence demand by offering incentives to consumers to use less energy overall, and/or to use it only at specific times.
In addition to keeping things in balance, the ESO also needs to procure a range of services from generators, to help keep the system safe, operational, and efficient. These services relate to technical characteristics of the grid, such as managing voltage support or stability constraints in specific parts of the network. They also include supporting grid inertia, which is falling because the transition to more renewable power involves a changing asset base. This means the system needs more fast-acting back up power.
The GB intermittency challenge
For Great Britain, there’s a separate but related challenge of the intermittent assets tending to exist on the periphery of the grid. Just think about the remote onshore wind generation happening in Scotland and the offshore wind farms in the North Sea. And then consider the solar farms in the south west and south east extremities of the country.
To ensure power can flow from the point of generation to the point of consumption, such locations result in the network requiring significant investment in power transmission. While awaiting this investment in infrastructure, the GB system will continue to have insufficient network capacity to transport the power. These ‘constraints’ mean the ESO must turn off generation in one part of the network to allow generators to turn on in another part. These actions cost over £1.5bn in 2023-24; a cost that, ultimately, consumers had to pay.
A changing generation mix also has ramifications for how the ESO procures other essential services. These include system restoration, in the event of a total or partial blackout, and response and reserve services that manage short-duration supply events. However, it’s worth noting that the ESO is responding proactively to the changing system and exploring restart provision from novel providers.
Also of note is the ESO’s expectation of balancing costs increasing between now and 2030. Driving this rise is the increased constraint costs associated with the speed of transitioning to a system with significant quantities of new renewable generation connected to it.
The ESO in Great Britain has been forward-thinking and flexible in deploying new services to meet the changing nature of the energy system. It’s also looking to minimise balancing costs through its “Balancing Cost Portfolio” workstream and by making operational changes to how it manages balancing. Network reinforcement and build-out also has a direct link to the costs of balancing the system, especially in terms of constraint costs.
The need for flexibility
There are four main options for delivering system flexibility without a reliance on fossil-fired thermal sources:
- Shifting demand – through demand-side response (DSR) mechanisms
- Adjusting supply – by developing and utilising low-carbon dispatchable power sources (e.g. hydrogen-fired power stations or gas-fired power stations where carbon is captured and permanently sequestered)
- Doing both – through energy storage solutions and interconnections
- Innovating technologically – developing new power sources
DSR
This approach involves shifting electricity demand away from peak times, such as winter evenings, and towards periods when demand’s lower. Doing this makes managing large volumes of intermittent renewable generation easier and can significantly reduce the overall cost of a decarbonised system.
The cost reduction occurs because shifting demand to off-peak periods when renewable output is available means the country’s using cheaper power. DSR should also be able to provide ancillary services, such as frequency response.
Low-carbon dispatchable power
Flexible, low-carbon energy sources and storage are vital to providing the adequacy needed for a reliable energy system. Gas carbon capture and storage (CCS) or hydrogen generation, plus large scale electricity storage, can replace the flexibility that natural gas provides today and lead to lower emissions in future. (Even so, a small amount of natural gas is likely to remain online, to ensure a secure and reliable power system.)
However, for this evolution to take place, there needs to be progress in the development and commercialisation of these technologies, changes in energy policy, as well as the regulatory and market framework – particularly for long-duration storage. Also, there’ll have to be agreement about the business models for hydrogen transport and storage to kick-start the delivery of the necessary infrastructure.
Storage
Although the availability of pumped hydro storage in the UK is somewhat limited, we’re proud to say it includes our plant at Cruachan. While its current capacity is 440MW, we’re planning to more than double that in the coming years.
The other option in this category involves deploying bulk and distributed energy storage (e.g. battery technologies) to reduce the need for additional backup capacity, generation and infrastructure. These technologies will store electricity when demand is low and discharge it when demand’s high.
Interconnections
The UK has access to extra capacity from Belgium, Denmark, France, Ireland, the Netherlands, and Norway. Increasing this interconnectivity could involve taking more power from these countries, or extending the interconnectors to additional markets.
Whatever the strategy, additional interconnectivity can improve the UK’s security of supply and operating efficiency. It may also help deal with intermittency by taking advantage of different weather patterns and demand profiles when they occur in the connected markets.
New technologies
One example is the development of electrolysis for producing hydrogen, which is then stored for conversion to power. However, in general, new technology needs significant investment and time to develop – the production of so-called green (renewable) hydrogen is not commercially viable at present, for example.
Drax helps address flexibility
Drax Power Station, our renewable biomass plant in North Yorkshire, provides around 11% of the UK's electricity. As a baseload generator, the plant doesn't suffer the intermittency issues of other renewable sources.
What’s more, we’ve tested and will soon deploy bioenergy with carbon capture and storage (BECCS) technology. The BECCS process secures the carbon emissions resulting from power generation using biomass pellets, then safely and permanently locks them away underground. The aim is to make the plant carbon negative.
We're also investing in a significant upgrade of our pumped storage hydro assets at Cruachan, in Scotland, to deliver flexible power at peak times and support the ESO.
Separately, we're working closely with our customers and partners to deploy flexibility through DSR. We're the country’s largest provider of industrial and commercial flexibility to the ESO's Demand Flexibility Service. To find out more, see our explainer.
