The costs of variability due to the presence of large quantities of intermittent/variable wind energy on the UK national grid.
In order to comply with legislation from the European Union, the UK’s renewable energy target (to produce 15% of final energy consumption from renewable sources by 2020) may require between 35 and 40% of our electricity to come from renewable energy sources by 2020. After 2020, a higher proportion may be needed. A significant amount of this renewable electricity is likely to come from wind, and the variability of this power needs to be managed. Although aspects of the management of wind variability can be controversial, utilities the world over generally agree that there is no fundamental technical reason why high proportions of wind energy cannot be assimilated into the system. There is a large body of literature on the topic and the steady growth of wind power, worldwide, indicates that it is seen as a robust choice for reducing greenhouse gas emissions.
An understanding of the impacts of the variable sources of renewable energy must take into account the wider issues associated with managing electricity systems. Modern integrated networks are designed to cope with ‘shocks’ such as the sudden loss of large thermal power stations and with uncertainties in consumer demand. As the tools to deal with these are already available the key question is the extent to which the introduction of large amounts of wind energy will increase the overall uncertainty in matching supply and demand.
This extra uncertainty means that additional short-term reserves are needed to guarantee the security of the system. The extra cost of these reserves — with wind providing 20% of electricity consumption – is unlikely to be more than £1.20/MWh on electricity bills (a little over 1% on domestic bills). With 40% of electricity provided by wind, the corresponding figure would be £2.8/MWh.
The costs of additional reserves are one component of ‘the costs of wind variability’. A second is the backup cost and the third is ‘constraint costs’. No special backup provisions need to be made for wind energy. All generating plants make use of a common pool of backup plant that is typically around 20% of the peak demand on the electricity network. When wind is introduced, system operators do not rely on the rated power of all the installed wind farms being available at the times of peak demand, but a lower amount – roughly 30% of the rated capacity at low penetration levels, falling to about 15% at high penetration levels. This lower ‘capacity credit’ gives rise to a modest ‘backup cost’.
‘Constraint costs’ arise when the output from the wind turbines exceeds the demand on the electricity network. They are unlikely to arise until wind energy is contributing around 25% of electricity requirements. Overall, it is concluded that the additional costs associated with variability – with wind power providing up to about 40% of all electricity, are quite small. If wind provides 22% of electricity by 2020 (as modelling for Government suggests), variability costs would increase the domestic electricity price by about 2%. Further increases in the level of wind penetration beyond that point are feasible and do not rely on the introduction of new technology.
There are numerous technical innovations at various stages of development that can mitigate the costs associated with variability. Improved methods of wind prediction are under development worldwide and could potentially reduce the costs of additional reserve by around 30%. Most other mitigation measures reduce the costs of managing the electricity network as a whole. ‘Smart grids’, for example, cover a range of technologies that may reduce the costs of short-term reserves; additional interconnections with continental Europe, including ‘Supergrids’ also deliver system-wide benefits and aid the assimilation of variable renewables. Electric cars hold out the prospect of reduced emissions for the transport network as a whole and could act as a form of storage for the electricity network — for which the electricity generator would not have to pay.
The author David Milborrow is an energy consultant with 31 years experience in renewable energy. He was first involved in aerodynamic research at the research laboratories of the Central Electricity Generating Board before moving to their headquarters in 1984. From then until 1992 he was associated with policy development, including plans for some of the UK’s first wind farms. His association with variability issues goes back to 1988, when he managed a study for the CEGB that was one of ten carried out under the auspices of the European Commission. After privatisation — and becoming an independent consultant in 1992 — he completed further studies on the topic for a number of clients including the Canadian Wind Energy Association, Sustainable Energy Ireland, the Carbon Trust and the UK DTI. He also lectures on the topic at three universities.
He retains an interest in aerodynamic and engineering issues and has also carried out a number of studies on the economics of renewable energy sources, and comparisons with those of the thermal sources of electricity generation. He is, or has been, an adviser to a number of bodies including the European Commission, the DTI, and the Engineering and Physical Sciences Research Council. He is technical adviser to the journal WindPower Monthly and to the British Wind Energy Association.