The UK is in the process of massive power sector change, a no change is more critical than the DNO-DSO journey which will change the way the industry fundamentally works. The DSO model is the future of the industry, and if the existing DNOs do not step forward to take the role, then other organizations will do and are doing so. Given that there are existing RIIO ED1 commitments to meet and RIIO ED2 is now less than six years away, then the journey for the UK DNOs should start now. This is the first of a series of blogs we will be issuing on the topic; this blog sets the scene by identifying the change drivers in the industry, and providing an overview of the power system of the future.
What is driving change in the power distribution system?
As renewable energy production reduces in cost, deployment increases and drives power system autonomy and interconnection simultaneously. Coordination of the bulk power system across the national grid drives down renewable energy integration costs, and is a growing necessity given the current power needs of UK. In addition, the cost of renewable energy is falling for individual customers, and therefore customers increasingly own their own generation systems to provide themselves with resiliency in the event of grid failure, and a choice of where and how they source their power to manage cost.
It is likely that this will continue as the cost of most forms of distributed energy resources (DER) is still declining. Sources include micro-generation, biomass, wind, solar PV, and a multitude of distributed storage (DS) options – including electric vehicles (EV). The extrapolation of this trend suggests increasing penetration of DER and a larger proportion of existing consumers becoming simultaneous producers and consumers of power: Producer-Consumers “Prosumers”. With these technologies interacting with the grid at low-voltage levels, the power system architecture and organizational roles/relationships will also have to change. The system is currently designed to distribute electricity from generation through transmission, distribution, and on to consumers avoiding congestion and bottlenecks.
It is therefore not a question of whether the DSO and TSO of the future will become actors in a system which is predominantly DER supplied, but rather a question of when the tipping point occurs; and therefore what the system will look and have to operate like once this occurs. Solar sources now provide 14GW of power across the UK – which four years ago was the forecast for the UK in 2030. In addition, EVs accounted for 4.2% of new cars registered in the UK last year – this is an increase of 28% over the previous year. So clearly the tipping point is closer than many predicted, and it would not be surprising to see close to 50% of the UK’s power needs coming from DER in RIIO2. Indeed, some regions such as London and the South West may reach that point sooner given current uptake.
What does the power distribution system of the future look like?
Tomorrow’s system will need to manage increased volatility of net demand, reverse flows from DSO to TSO level when DER generation exceeding local demand, and complex/aggregated energy trading and contracts at a micro level. The market’s destination therefore must be able to aggregate and coordinate many Prosumer supply/demand points to allow the ongoing cohesive operation of the wider power system, whilst at the same time supporting the independence of the Prosumer to independently interact with their local system based upon their own needs.
What is more, if DNOs in particular fail to interact with the new individual Prosumers, as they move to DSO status, who are likely to be higher credit individuals; then they will be left with a customer base of lower credit households who are likely to be higher relative cost to maintain on the network.
UK network is structured in its current state as it is the most efficient use of prevailing geographically spread resources, i.e. to connect large power stations together. Therefore if the requirement in the future is to knit together all types of DER as sources of flexibility, then the current model potentially becomes unfit for purpose in its prevailing form. Inaction is not an opportunity for DNOs as they move towards the role of DSO, nor is inaction an option for the national TSO. If either attempts to maintain its existing business model, they run the risk of inefficient investment, infrastructure isolation, or becoming the owner of ‘stranded’ individual assets.
DSOs will continue to ensure sufficient delivery capacity in the distribution network, report faults, report status, and report anticipated demand up to TSO; but as DER and local power storage both increase, requiring greater system flexibility, the management information requirements will become more onerous. It is this that drives the TSO’s future to one of coordination and managing interdependence of DSOs, and supporting them through bulk supply capacity. This will require a closer day-to-day working relationship between TSO and DSO in order to keep the system reliable and stable. This model can already be observed operating in Germany, where small DSOs already provide upwards of 80% of load from DER and the TSO balances the system by pushing flow when required, and acting as a net importer from certain regions at high sunlight/low demand periods.
In conclusion, it can be seen that there is a clear call to urgent action for our incumbent DNOs to commence or accelerate their journey towards a DSO model if they are to take advantage of the opportunities available. In our next blog in the series will examine in more detail how a new model might operate in the UK power industry.