Local grid charging – what are the options?

Local grid charging is key for developing decentralised energy markets.
Published: Wed 11 Apr 2018

With the emergence of local renewable resources, a growing concern for distributors has been the loss of revenue from users going substantially off grid. At the same time, in some jurisdictions such as the UK, the distribution costs are recovered over regions with little or no consideration to locale or other factors.

With the potential for decentralised energy marketplaces with local generation and peer-to-peer trading, the concept of local grid charging – in which the distribution charge is related to the local network usage – is key with the incentive it brings for users.

Local power matching

The opportunity to develop local grid charging has come to the fore with the emergence of peer-to-peer platforms, such as Open Utility’s Piclo in the UK, which ‘matches’ local renewable generators to users.

In order to investigate some options, Open Utility has engaged in a study with the distribution network operator (DNO) Western Power Distribution (WPD). As a first step, the focus has been on pricing models that could incentivise local matching.

Other participants in the study, which comprised interviews, literature research and economic modelling, were economics consultancy Reckon, sustainable energy advisor Regen and clean energy law company Lux Nova.

Local pricing models

The study considers four local pricing models.

Two of these are variations of private wires models in which the generator supplies electricity to the consumer via a privately owned wire. One of these, the Network Replicating Private Wires model, replicates the local DNO assets in an arrangement involving a single generator supplying electricity under contract to at least one independent customer using wires that are owned and maintained by one or both parties. The other, the Virtual Private Wires model, utilises the DNO’s spare capacity routed over existing assets under a private leasing arrangement.

The other two models are variations of the current Distribution Use of System (DuoS) charges, with the basis that locally matched electricity does not use higher network levels than that at which the matching takes place. Customers can then be charged the costs attributable to the network levels they are using, rather than also all the higher levels as at present.

Impacts of pricing models

The study found that of these options, the Virtual Private Wires model would be the most favourable for participants and with strong signals for local matching. However, regulatory changes would be needed to implement the model, and these are unlikely to be agreed as participants would avoid paying certain policy costs which would then need to be borne by wider electricity customers.

The locational DUoS charging models are the fairest and, in principle, the most scalable of the alternatives. However, they provide far weaker price signals to encourage local matching than either of the private wires models. Furthermore, there would be significant complexities to implementation, including how to share the value of matching fairly between generators and end-users.

Commenting on the findings, and explaining that none of these models provided the right mix of encouraging local matching while also being fair to non-participants, James Johnston, CEO of First Utility, says: “It’s a complex area and ultimately comes down to fairness. A model has to be fair to all the parties – the network operator, the supply and demand participants and the wider distribution customers.”

Johnston says a key learning is the tension between the strength of price signals and fairness. On the one hand, it’s important for the financial incentives to be strong enough to influence behaviour, as in the private wires models. On the other, however, the mechanism must have low barriers to entry to allow a wide variety of grid customers to participate, as in the locational DUoS models.

“We believe there are ways of incorporating the best elements of the two sets of models,” says Johnston. “In particular, it’s felt there is scope for exploring models which involve a more dynamic price component,” he adds, saying that Open Utility wants to start testing these and other models in demonstrators and trials.

DSO benefits

An additional notable finding of the study was that contrary to the view that the distribution operator would lose revenue with local matching and charging, it could benefit. In WPD’s case, with the prospect of a £224.5m, eight-year network upgrade, the company could save up to £28m per year in deferrals through a reduction or delay of peak flow growth.

In addition, preliminary findings suggest that if just 10% of customers used local matching they could make combined annual savings of £1m on avoided generation through reduced losses, plus a further £0.2m in avoided carbon costs.