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Balancing renewables in Denmark

By Dave Elliott

Denmark has been at the forefront of the renewable energy revolution and although it has seen some political retrenchment recently, it is still pressing ahead with the next phase,  which includes the need for more grid balancing. It’s mainly a problem of over-supply. Wind and other renewables now supply over 43% of annual power, and that at times means there is too much electricity available. How is that dealt with?

Much of the surplus is exported (over 6GW equivalent p.a.) and used, for example, by Norway to pump extra water up behind their hydro reservoirs, if there is room! When power is needed, the extra head can be run through the hydro turbines and if necessary Denmark can, in effect, reimport it to meet shortfalls, though at a higher price than it sold it initially. So this process adds to the cost. And there may be limits to how much Denmark can export – not everyone will need power when it’s available.

There are also other balancing options, however, including the conventional gas plant backup approach and the use of balancing markets.

Combined Heat and Power (CHP) plants linked to district heating (DH) networks and heat stores can also play a role in this. When there is too much wind-derived power (and low prices), CHP power output is reduced to compensate. A 2015 study from Agora Energiewende looks at Denmark’s use of CHP pricing to boost decentralized grid flexibility: ‘In times of low electricity prices, district heating companies are incentivized to shift production from CHP plants to boilers or to “bypass” the steam turbines at the CHP plants. At low or negative power prices, this bypass is used for exclusive heat production. When prices recover, the plant can quickly switch back into a co-generation model, producing combined heat and power’.

Although high wind periods usually occur in winter when heat demand is high, there may still be times when there is too much heat being produced via this variable CHP approach, in which case it can be stored, ready for use when heat demand rises and/or when wind availability is low and the CHP plants are mostly used to generate power – many large hot water heat stores are now in place. They can also be topped up with heat using immersion heaters powered with surplus electricity from wind. The Nordic Folkecentre for Renewable Energy in Denmark sees this as preferable to and more economically attractive than exporting the surplus – or, of course, to curtailing output from wind projects when output is high and demand low.

Solar heat collectors can also be used to top up the heat stores – there are several large solar projects, some with interseasonal heat stores in Denmark linked to district heating networks. The aim is that by 2050, 40% of the DH system will be solar fed.

Heat pumps can also be run on the excess wind power to produce heat for district heating networks/stores, but the Agora report above notes that Whereas heat pumps installed in a district heating system cost on the order of 0.7 million euros per MW of heat capacity, the cost of electric boilers is only approximately 0.15 million euros per MW’.  In addition ‘heat pumps need a high number of operation hours – providing base load or intermediate load – to be economically viable. Electric boilers, on the other hand, offer cheap capacity and may be profitable with less than 500 full load hours of operation’.

Biomass-fueled CHP is now common in Denmark, so emissions/kWh of total energy, already low, given high efficiency CHP are even less. Agora adds that ‘under the current regulatory regime, heat pumps are not competitive with biomass technologies’ i.e. DH boilers/CHP. However, the biomass resource is environmentally constrained, so direct use of surplus wind-derived electricity or power-to-gas electrolytic conversion of it to hydrogen and then methane for direct heating or CHP/DH, looks to be a better idea, given that there is no shortage of, in effect, free surplus. That can compensate for the relatively low efficiency of conversion in this multi-stage process.

Denmark is also looking to smart grid demand management. This can reduce demand peaks, e.g. shifting demand to when wind is more available. It can avoid wasteful losses and cut costs. Certainly there are some interesting projects on and ideas about comprehensive smart energy systems and smart grids, integrating all aspects of energy generation and use.

All this is set in a context where costs are all important, given the strength of market-orientated politics in Denmark. Pressure is on to limit subsidies, and for some new wind projects to be delayed or abandoned, nearshore wind projects especially.

That seems tragic, since there are some excellent new offshore wind projects planned in the area, with prices falling dramatically. Danish wind company DONG put in a successful bid for two 350MW projects 22 miles off the Dutch coast at €72.7/MWh (~£61), well below those for new projects off the UK, which are to be offered strike prices in the next CfD round of around £105/MWh. But Swedish utility Vattenfall has now done even better, with a winning bid for 170MW and 180MW projects near the Danish coast at €63.8 MWh (~£54). Bloomberg actually cited €60 as the cost, and said it was so low because the turbines were ‘unusually close to the shore, leading to lower costs for foundations and transportation’, although that meant you ‘lose a key advantage of not having a visual impact.’

These projects are expected to start up in 2020, although there are worries that, as near shore projects, they may fall foul of Denmark’s proposed new renewables policy. Danish energy minister Lars Lilleholt said ‘It is no secret that the government wants to abandon the construction of the coastal wind turbines’. He explained that ‘the government believes “green power” at sea, where applicable, should be further away from the coast. It will not disfigure our unique coastlines and should be seen in light of the fact that the price of offshore wind far out at sea, according to the wind industry itself, is expected to be halved over the next ten years’.

Lilleholt also argued that the costs still remain too high: ‘It is great that the industry has managed to lower the price so significantly. Support costs however will be almost double or DKK 1.7 billion higher than expected when we made the energy agreement in 2012. This is a significant additional expense that the government has not allocated funding for in our 2025 plan.’ It is true that the new winning bid prices do not include transmission or balancing costs, so that the final cost to consumers will be higher, and it is that, and the total cost to Denmark, that evidently worries the government. Vattenfall noted that the price of the new projects was ‘more than 30% under the price cap in the energy agreement from 2012 set’ – €91/MWh. But the Danish energy ministry has said electricity prices had fallen since the 2012 agreement, so that support levels ought to be lower.

However, with Vattenfall winning a tender to build the 600MW Danish Kriegers Flak offshore wind project on the Baltic coast with a bid of €49.9/MWh, the battle on costs continues.

The drive to be more competitive does have its problems. Some of the many local wind co-ops that sprouted in Denmark in the early years of its rapid on-shore wind expansion have not been able to survive or upgrade to new, more efficient turbines. Some have been taken over by private companies. Moreover, few new co-ops seem to be emerging, although as the Folkecentre report notes, some still are.

So the news is mixed. But despite the slowdowns and cutbacks, Denmark still remains at the forefront of renewables, and hopefully, despite the political retrenchment, it can keep to its ambitious target of being carbon neutral by 2050.

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