Proponents of grid-scale plants often argue that bigger is better from a national benefit perspective, due to the lower capital cost (per-MW of installed generation capacity) compared to rooftop solar. But this argument ignores the fact that the value of electricity varies depending on the location of investment. A higher cost form of generation may be the best option if it is located in a part of the country that has sufficiently higher prices (and therefore more value).

It is not appropriate to compare the long-run marginal cost (LRMC) of grid-connected power plants to the LRMC of rooftop solar because of that different value equation. The most efficient investment path for New Zealand is not simply the one that deploys the lowest LRMC plant, irrespective of whether it is transmission connected, distribution connected or behind-the-meter. 

The national discussion about building the ‘right’ plant for the system is anchored around a decades-old framework that assumes it will be directly connected to the transmission grid, and will earn the wholesale electricity price for its output. However, today there are over 60,000 power plants on rooftops and these need to be factored into the calculations. They don’t earn the wholesale price for their output, they “save” (or avoid) the retail price, which is generally around double the wholesale price.

New technology is changing the economic equation and regulators need to examine the architecture - which was mostly drafted over 20 years ago - to see if it has in-built inadequacies, outdated assumptions and biases against distributed resources. 

To evaluate the ‘value’ of electricity in the distribution network and - ultimately - at the customer’s premises, it is important to consider the ‘delivered cost of energy’ as faced by a customer. There are costs that exist in the supply chain - from the grid through to the house or business - that would be reduced by an investment in rooftop solar and batteries and these need to be factored in. 

In the world of fossil fuels, we talk about the ‘price at the pump’ or the ‘price at the bottle’, as that is the price paid by the customer, despite the fact that numerous delivery costs and levies are included in that price. Delivered energy costs also need to be used when it comes to analysing electricity. 

Customers who install rooftop solar are likely to be motivated to change their demand behaviour to maximise the use of daytime solar, which benefits them economically. These customers will also be able to effectively shift their solar production from the time it is produced (daytime) into morning or evening peaks through the use of battery storage or demand-shifting, which has value to the system, but isn’t being valued appropriately. 

Retailers should not make a profit on generation export that is the result of a customer funded investment, which is happening when export rates are below the average wholesale price. At the very least, exported solar should be paid the wholesale price, cost-reflective tariffs need to be mandated and, if distributed resources create greater value (per kW) than grid-connected resources, the authorities should be trying harder to reduce the red tape associated with investment in these resources. 

Distribution networks should also be capable of absorbing the exports from significantly more rooftop solar installations than exist today, without significant additional investment in network upgrades.
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