Features

The UK Government, like others in Europe and around the world, has set itself a target of 20% renewable energy by 2020. Last week the UK Government unveiled its Renewable Energy Strategy¹, which set a target of 30% of electricity from renewable sources by 2020, up from the current level of 5.5%. Realizing this target will mean a significant shift away from the country’s current energy mix towards a higher proportion of low-carbon technologies. The renewable energy component could come from hydro, solar, geothermal or, most likely in the UK, wind and marine energy. The wind sector is the best developed and looks set for a major expansion in the UK.

But in even the windiest locations like the North Sea, there are still days when the wind doesn’t blow. How will the country’s electricity infrastructure – the national grid – cope with demand when the wind doesn’t blow? Intermittency is a serious issue for many renewable energy sources, but particularly wind because of its unpredictability. Ahead of the Government’s renewables strategy, the UK’s business lobby group the CBI is calling for the target for wind to be reigned in to favour other low-carbon energy sources such as clean coal and nuclear, as well as other renewables².

According to a report from the CBI, if the UK pursues an expansion of wind power at the expense of other forms of energy, the country could find itself increasingly reliant on imported gas to supply power stations being used to balance intermittency. By 2030, according to research carried out for the CBI by McKinsey & Company, the UK could be relying on gas for 36% of its energy demand. Such a situation would make the UK vulnerable in terms of energy security and guaranteed supply, and also potentially subject to some of the highest and most volatile energy prices in Europe.

It is certainly the case that an increased proportion of wind output online will require some additional plant to become available when wind levels drop. And the CBI’s thinly veiled argument in favour of the big businesses of clean coal and nuclear power, may have a point – but is only part of the picture. A recent independent report by Pöyry Energy Consulting also finds that electricity markets will be profoundly affected by the growth of wind energy³. The impact of intermittency on the national grid will present energy sector operators and investors with some significant challenges. But, says Pöyry principal consultant James Cox, it will present opportunities as well.

Interestingly, the Pöyry report finds that response – generating plant able to come online in a few seconds – requirements do not grow significantly with more wind in the system. Reserve – generating plant available within a four-hour window – requirements will need to change, however. Adding other major renewable projects such as the Severn Barrage make the problem worse, says Cox, despite the predictability of its intermittency. The bottom line is that more renewables in the electricity grid will need a significant increase in reserve capacity. And this will present the market with a conundrum.

Meeting the UK’s carbon reduction and renewable targets could mean an extra 35-45 GW of wind energy in the electricity market by 2030. But the variability of wind generation output could be as much as 13% annually, according to Pöyry’s analysis. Problems could arise when temperatures are low and demand is high, but there is virtually no wind. In this situation, the British electricity market becomes very risky and prices could spike up to £8000/MWh or more. But when the wind picks up again, the price could drop right back down again to zero or even negative prices. This kind of scenario puts entire system flexing at the behest of the weather. It would be, says Cox, a very extreme position for the market to be in. For investors, there would be little incentive to support conventional power generating facilities able to ramp up at short notice to balance demand and wind intermittency.

One option examined by Pöyry is interconnection – its analysis looked at the neighbouring Irish market. The Irish market experiences even more variable wind output –up to almost 25% - but operates on a different system. The Single Electricity Market (SEM) in Ireland operates on a capacity payment method where suppliers receive a fixed payment annually. This incentivises operators to build plant that provides quick response to drops in wind output, while lowering price spikes and price volatility. Generators are, therefore, less at the whim of the wind and better able to manage the prospect of having energy generating facilities on the grid that are only ramped up very rarely.
“We’re not certain that the Irish mechanism would work in Britain,” says Cox, “But it is definitely one possible solution that could make a difference.”

However, while interconnection does assist in the physical management of intermittency it is not a silver bullet. Interestingly, while interconnection could be critically important to allowing a smaller market like the Irish one accommodate higher levels of wind capacity, it does make it prone to the price spikes of its more dominant neighbour. Conversely, the smallness of the Irish market and its geographical closeness in terms of prevailing weather conditions makes interconnection only a partial solution to the issue of intermittency in the British market.

A recent consultation document from the National Grid itself goes rather further⁴. It suggests that connecting the British market to a wider network extending over Northern Europe could significantly manage the problems of intermittency. However, the Pöyry report notes that if different regional markets in Northern Europe are interconnected, and price differentials removed, the commercial case for a larger European network becomes challenging and investment would likely have to come from grid operators themselves or governments.

National Grid, which is the UK’s main electricity transmission network operator, already has one interconnection route to France and is constructing another to the Netherlands. It is also considering other links to Norway, Belgium and a second link to France. In future, says Stewart Larque of National Grid, system operators in Europe will have to collaborate on data sharing to manage variability over a wider area.

In fact, National Grid’s report says there are many ways to help address intermittency through demand management strategies including smart metering and ‘Economy 7’ type tariffs, small-scale and domestic electricity generation, electric vehicles and new energy storage technologies on the horizon such as supercapacitors and compressed air.

“Intermittency is certainly an issue that needs addressing,” says Larque, “but it isn’t just about drawing balancing power, it’s also about demand side management.”

In the future, technologies like smart metering could allow SMEs and residential customer to become part of the balancing solution, along with the large industrial concerns such as aluminium smelters that are able to switch off at short notice at times of peak demand.

Aggregating services could pool the resources of SMEs and individual consumers to provide balancing. According to Larque, just bringing together all residential fridges in a smart system could provide balancing of up to 500 MW – equivalent to one large fossil-fuelled power station. Electric vehicles could be another very useful tool in National Grid’s toolkit, suggests Larque, providing a block of demand that could potentially be moved around through smart metering and customer incentives to manage peaks and fill troughs in demand.

However, while the National Grid report admits that accommodating a greater proportion of wind could lead to an increase in short term operating reserve from 4 GW now to 8 GW by 2020, it anticipates that more experience and these new tools, as well as new nuclear capacity, will improve its forecasting and ability to manage demand.

“We are of the opinion that there are no technical barriers to accommodating more wind on the system,” says Larque.

The feeling is echoed by another recently published report, this time commissioned by environmental groups Friends of the Earth, Greenpeace, RSPB and WWF⁵. Report author David Milborrow agrees that the National Grid is more than able to manage wind variability, which he says fluctuates considerably less than consumer demand. If the grid can manage these variations in demand, then it should also be able to manage varying supply.

“There are no significant costs associated with managing variability,” says Milborrow. “Utilities worldwide generally agree there is no fundamental technical reason why high proportions of wind cannot be assimilated without the lights going out.”

Cox agrees that despite the intermittency problems of wind, there is nothing to suggest that overall wind penetration up to 43% cannot be accommodated in the UK grid. Operators in the energy sector just need to be aware of the issues and the ways to mitigate them, he says. One factor that will make all these issues easier to mitigate, points out National Grid’s report is greater energy efficiency and reducing electricity demand in the first place.

Cordelia Sealy

For further information:

1. Renewable Energy Strategy: www.hmg.gov.uk/lowcarbon
2. Decision Time. CBI, (July 2009) www.cbi.org.uk/
3. Impact of Intermittency: How wind variability could change the shape of British and Irish electricity markets. Pöyry Energy Consulting, (July 2009). http://www.ilexenergy.com/pages/documents/reports/renewables/Intermittency%20Public%20Report%202_0.pdf
4. Operating the Electricity Transmission Networks in 2020. National Grid, (June 2009). http://www.nationalgrid.com/uk/Electricity/Operating+in+2020