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Prosumer integration

By Dave Elliott

The German Environment Agency (UBA) has produced a comprehensive review of options for removing almost all (95%) greenhouse gas emission by 2050, based on the existing 80% renewables programme for electricity supply, but also looking at all the other sectors – including heating and transport. As I said in my coverage in an earlier post, that is pretty challenging. But it says it can be done. www.umweltbundesamt.de/publikationen/germany-2050-a-greenhouse-gas-neutral-country

However, the UBA report doesn’t look at the economics of any of the options – it’s focused on overall technical system viability. The practical economics of renewables do, though, show up when we look at specific deployment issues. For example, the German programme would presumably rely heavily on domestic prosumer self-generation, which already accounts for over 35% of the green power being produced in Germany. But there are some controversies relating to the issue of grid integration, management and balancing, and who pays for it. That has led to system charges being imposed on prosumers. And with domestic-scale solar PV self-generation catching on around the world, there have also been battles over net metering grid charges in the USA, and in Spain, a bitterly opposed tax on PV-linked domestic storage.

So it is not just a technical issue of system charges and grid integration. It can be politically contentious since self-generators clearly can afford to invest in expensive systems whereas other less wealthy consumers may see them as free riding if they don’t pay the system costs. Equally though power companies may impose charges punitively, to protect their generation market.

Here’s how an EC Insight study of what it calls ‘self consumption’ (SC) using renewable energy systems (RES) puts it: ‘A delicate topic is the distribution of the costs, be it costs of the power grid or additional production costs of RES. SC tends to reallocate costs from some prosumers that can afford the necessary investments to consumers that have to receive their power only from the common grid. The latter being charged a higher share of grid costs, levies and taxes. Interesting proposals to change the collection of grid costs such as time-varying grid charges or charges split by volume and maximum load were made by different institutions.’ But it says SC is well worth it, since, with proper demand-side management and storage included, the overall cost of system integration can be reduced by 20%. So everyone can benefit.

The EC Insight study says that self-consumption ‘can contribute to market integration of RES’. Although grid integration is needed for top-up/balancing, along with enhancements to capture the advantages of SC for the full system, if done right, ‘in combination with electricity storage and demand response (DR), SC can facilitate the integration of variable renewables onto the grid and lower the overall costs of the energy system through load shifting particularly if storage and DR is managed using ICT and algorithms controlling charging cycles and usage of electric devices’.

In terms of practical management, the paper notes that, mostly, ‘power production takes place when residents are not at home, pursuing their profession or other activities of daily life. Consequently, estimated the direct SC potential varies between 17% and 44% depending on household-size and irradiation exposure’. One way to improve that is via demand response – ‘managing electricity demand in a way that peak energy use is shifted to off-peak periods enabling higher rates of self-consumption or, more generally, the adaption of demand to grid issues’.

Unless there are time-varying charges, that involves voluntary smart self-management of energy uses. And that might need some extra cash incentive initially. Similarly for storage. But it’s worth doing since ‘managed in the right way, self-consumption of RES can lower the pressure on the electricity grid of feed-in of electricity from RES in scenarios with a very high share of renewables’. It does need demand response and storage extension, because, otherwise, on its own ‘power self-consumed does not change the residual load, since it is neither consumed from the grid nor fed-in’. Moreover ‘the exploitation of RES leads to high peaks in production and a low residual load during times of high wind speeds or intense sunshine hours. At other periods there may be little contribution of RES to cover electricity demand due to low wind speeds or cloudy days for PV production’. But ‘there is evidence that self-consumption extended by storage and demand response measures can reduce the additional integration costs of the integration of PV at high penetration levels (18% of total electricity production) by around 20% over all countries that were considered in the study’ – the UK, Germany, Belgium and France: http://t.ymlp349.com/usqseaxaeujuwakajbaraush/click.php

While there may be ways to avoid conflicts in the domestic electricity sector, there are some other tricky deployment issues when we look at heating and transport. For example, the UK is planning to replace domestic gas heating in part by electric heat pumps, and also expects consumers to charge battery electric vehicles (BEVs) at home at night. Won’t all this put a massive strain on the power grid, and local distribution links especially, and lead to conflict over priorities? If some people insist on running everything flat out there could be local brown outs; not everyone will be prosumers able to meet these needs themselves and even prosumers with large domestic battery storage backup may need to import power in the depths of winter.

How big is the problem? Certainly it has been argued that, since in the UK the gas grid handles 3-4 time more energy than the power grid, and vehicles also use a huge amount of energy, the power grid would have to be vastly enhanced if it is to meet these extra loads, which will occur at peak demand time in the evening. Some attempts have been made to quantify the impact. A BRE study back in 2008 suggested, surprisingly, that if domestic heat pumps replaced gas boilers there would only be a 2% rise in peak electricity demand over what it would have been otherwise by 2050, whereas peak demand could rise 20% with large-scale BEV charging.  http://www.gov.uk/government/uploads/system/uploads/attachment_data/file/48191/3150-final-report-changing-energy-use.pdf By contrast, a 2014 EA study for DECC found the use of heat pumps and electric vehicles would significantly increase the load on local distribution networks, heat pumps adding 60% to the cost of network links for the low carbon system they envisaged, BEVs 38%. However, they said that local generation options such as distributed solar PV and wind had low or no impact on distribution network investment in 2015-30. In fact, they offset load growth imposed by the electrification of heating and transport. http://www.gov.uk/government/uploads/system/uploads/attachment_data/file/370648/Final_Report_-_Impact_of_Policy_that_Drives_Low_Carbon_Technologies_on_Distribution_Networks_.pdf

It’s not clear if that will be enough. A more recent report, looking at the evolution of load curves to 2050 in the UK and Germany, shows peak loads rising by about 23% above the change in annual demand, to 103 GW in Germany and 92 GW in Britain. It added: ‘Sensitivities around electrification show that a million extra heat pumps or electric vehicles add up to 1.5 GW to peak demand.’ www.sciencedirect.com/science/article/pii/S0360544215008385  Big, but not impossible to deal with – for 1 million households. But not for 20 million or more (for each); that would be very hard.

Meeting heat demand with CHP/district heating/storage would arguably make more sense, wherever possible, with biogas being a low-carbon fuel option, and that system would also offer a grid-balancing option. On the BEV side, it’s argued that the peak could be softened by sensible management: http://longtailpipe.com/2015/04/16/fast-charging-electric-cars-wont-swamp-electricity-grid-if-done-intelligently 

Convinced? It depends on timing! And maybe time-based pricing. And, increasingly, on conflicting air con loads too. A complex topic. But the EC Insight paper mentioned above says that, if electric vehicles made up just 10% of the market in Germany, there could be a 7.6 GW peak load on the grid, assuming only 50% of the BEVs were charging simultaneously. It’s something that needs to be taken on board. Currently, in a test programme, a California utility is paying drivers of BMW electric cars to delay charging their vehicles when the power grid is under pressure. That’s not going to be a commercially viable approach when and if BEV use rises! http://www.renewableenergyworld.com/articles/2015/08/vehicle-to-grid-energy-storage-experiment-underway-in-california.html

*Thanks for Jo Abbess from Claverton Energy Group for some of the links. She has been looking at these issues: http://www.joabbess.com/2015/08/02/the-trouble-with-electrificandum-1/

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