By Dave Elliott
A recent report says that long distance transmission grids offer many advantages including enhanced cross-EU trade and grid balancing opportunities, enabling high levels of renewables to be used while reducing curtailment of occasional surpluses. The European Network of Transmission System Operators for Electricity group had already addressed the development of the pan-EU electricity transmission network up to 2030 in a Ten-Year Network Development Plan. Starting with that, the e-Highway 2050 research and innovation project has now looked to 2050: it deals with the transition paths for the whole power system, with a focus on the transmission network, to support the European Union in reaching a low carbon economy by 2050.
Five scenarios are explored, including three with significant amounts of nuclear power (19-25%), but also one with 100% renewables, in which wind supplies around 52% of EU electricity and solar 24% by 2050, and also a ‘small and local’ scenario in which energy efficiency cuts demand drastically (by 50%), biomass supplies 19%, but nuclear still supplies 10%. In the large-scale renewables scenario, solar projects in North Africa cover around 7% of the demand in Europe. The study lays out some of the key technical options, as well as indicating the policy issues ahead.
The detailed simulations show that the 2030 transmission network would not be sufficient to support the 2050 energy scenarios. Indeed, during significant periods, grid congestion would prevent some available generation from supplying loads and large amounts of renewable output would be curtailed. To compensate, thermal generation would have to be used, emitting carbon dioxide.
To tackle these issues, different proposed architectures of the transmission grid have been developed and compared to assess their techno-economic efficiency. They include the development of major North-South transmission corridors. That may not have to involve a completely new grid system. It’s claimed that, with some enhancement, the proposed architectures could be integrated in with the present or 2030 grid, and some of the links required can be made by reinforcing the current AC power grids, without the need for too much disruption. However, some new grid links would also be needed, since High Voltage Direct Current (HVDC) grids are better suited for long distance transmission. Though expensive, ‘for terrestrial HVDC applications, underground cables have proven their reliability and attractiveness for long distance power transmission and are now being seen as a solution for future long distance transmission based on the experience gained from long HVDC submarine cable links’.
The cost of grid expansion/upgrade depends on the scenario, but is put at €100-400 bn, although that would be offset by the improved use of energy sources, with up to 500TWh of renewable curtailment being avoided annually. However, curtailment still remains a problem. ‘Even with a hypothetic infinite network and with the significant amount of storage and DSM [demand-side management] assumed in the scenarios, some renewable generation is curtailed in the scenarios with high shares of renewables’. For example, in the 100% renewables scenario, PV solar curtailment reaches 8% of annual renewables generation, on average, with a 9.5% spillage overall (308 TWh by 2050). But then the study doesn’t look at Power to Grid (P2G) options, which might reduce or use that, as can other types of storage, although the 100% renewable scenario does already have 113GW of pumped hydro storage. However, it suggests that options like P2G be looked at in further work, and notes that ‘a combination of all the solutions might… lead to more promising answers to the system challenges’.
In terms of making it all happen, the study says ‘one of the key challenges to ensure a swift project realisation is providing the necessary financing conditions for the transmission network owners to finance the construction of infrastructure. Public sector support and rate-adders for strategic projects could push the project forward by financial stimuli throughout the most risky project phases, but may be insufficient to overcome the entire challenge’. However, ‘to provide the correct signal for transmission network investment, it is fundamental to create a fair, stable and predictable risk-reward mechanism which takes into account the different life-cycle stages of an infrastructure project. This implies that regulatory regimes should provide a forward-looking, long-term commitment and provide clarity to limit regulatory risk for investors’.
It will certainly be a challenge since ‘the higher complexity of electricity systems by 2050, characterized by higher shares of RES [renewables], (and) more variable electricity demand (electric vehicles, heat pumps), imply a higher diversity of costs and benefits that network users incur on the system. Since network charging structures currently often take a typical average situation as point of departure, increasing gaps between network charges and true costs of network users for the grid are observed’.
The study notes that regulatory and institutional changes are underway, although they are happening too slowly: ‘there is a clear need to complete the internal energy market and to ensure regional market integration in all time-frames forward, day-ahead, intra-day and real-time)’, and ‘it will be crucial to incentivise market actors to ensure correct and rational behaviour in order to tackle ever-increasing system security aspects. Well-designed balancing markets are a key requirement and electricity markets should contain a well-defined resource adequacy objective’, with there also being a need for, ‘further regional security monitoring and control mechanisms closer to real-time over larger geographical areas’, in order to deal with the high share of renewable generation.
So there is a lot to do at all levels, technical, operational and institutional, if the e-Highway approach outlined is to be followed up. Some, however, are not convinced that it’s possible, or at least can see major problems with trying to integrate in large amounts of renewables. In his useful review of the study, Paul-Frederik Bach says ‘In the most conventional scenario, “Fossil & nuclear”, European flexible resources must cover about 500 GW load variation. The dispatchable generation covers 78% of the energy consumption. In “100% RES” the range will be about 900 GW, and the dispatchable generation covers 30% of the energy consumption. Spillage up to 400 GW must be absorbed.’ He adds ‘covering a larger demand variation with smaller controllable resources will be a major challenge’.
That is clearly true – there will be a major role for flexible generation. However, as the study shows, the upgraded transmission grid can also help, and so can smart grids/P2G and other forms of storage. As this study indicates, technical innovation is clearly important, with new system-level developments possibly opening up new options. However, the reliance on long distance transmission and exchange of energy may mean that the operational and policy side, and the need for institutional change, will be the main issues, as has been suggested in an interesting exploration of the management and geopolitics of renewables by Scholten and Bosman. They ask: ‘How to manage the intermittency of power generation in cross-border networks; how will damages in one area incurred by fluctuating power in another area be resolved; what new modes of operating these systems may be required?’. Some good questions – with some of these issues already having to be faced by Germany.
However, a key final issue is Brexit – if the UK is really to be fully out of the EU, and not part of the new Energy Union framework, will any of this still be relevant to it? There will be more cross-channel links, allowing for some involvement with the emerging EU energy market, but the UK will be an outsider, with no say on how it develops.