The Electricity Authority released Guidelines on 10 June 2020 setting out requirements for Transpower to develop a new transmission pricing methodology (TPM).
A new TPM will not be in place before 1 April 2023, and significant detailed design effort is required by Transpower.
The headline outcome is transmission charges will be more fixed. The wholesale (nodal) price is intended as the main signal of impending transmission capacity constraints (congestion). Transpower is expected to look for alternatives – like using the flexibility of distributed energy resources (DER) – before building more substations, towers and lines.
The new TPM is intended to give electricity consumers and generators much-improved signals of the cost and value of using the transmission grid and provide:
- better signals of the true cost of using the grid — without high transmission charges if the grid is not congested, and grid investments paid for by those who benefit from them
- better use of the grid as New Zealanders take up electric vehicles and electrify process heat
- better investment in transmission — the right amount and at the right time.
What it could practically mean for solar and batteries
There are a range of likely near term and longer-term impacts for solar and batteries if the new TPM does what it says on the box. The following outlines the more likely impacts, based on available information.
Near Term - Now to 2023/24
In the near term, there is unlikely to be a material impact on end-user prices until the changes to transmission charges occur in 2023/24 (at the earliest). There shouldn’t be any impact until 2023/24 on the prevailing incentives to install and use solar and batteries.
Transpower may start to expand use of its Demand Response platform prior to 2023 to test the potential for DER ‘flexibility’ to manage transmission capacity constraints. This would direct additional revenue toward distributed energy resources, including combined solar and battery facilities, in locations with impending transmission capacity constraints (eg, the networks in the Waikato). The additional revenue should encourage investment in solar and batteries to the extent they provide flexibility and assist in managing transmission constraints.
Longer Term – 2023/24 Onwards
Transmission charges will change for different regions and customer groups across the country once the new charges are introduced. However, the new TPM will include a 3.5 per cent cap on the amount total electricity bills may increase as a direct result of the change (after inflation and volume growth).
Changes in transmission costs are not expected to be material relative to the average household bill and shouldn’t materially alter the prevailing incentive for households to maximise self-consumption of their solar generation. According to the Authority, in regions that are likely to experience an increase in transmission charges, the increase in the average household bill is estimated to be an average of $19 a year. In the districts where charges would rise, the impact in the first year on the average residential electricity bill should be less than 40 cents a week.
Transmission costs for some industrial consumers will rise significantly. It is likely these consumers have been successful in avoiding transmission costs to date. These industrial consumers too will be protected by a cap to allow them to adjust to the new charges. The cap on charges for industrial customers will phase out by increasing incrementally after five years. The commercial response of industrial customers to higher transmission costs will depend on the situation but includes exploring distributed generation to meet energy requirements rather than using grid-supplied electricity. For example, Fonterra may be better off using solar/battery options to electrify its plants rather than paying ‘extra’ for expanded transmission capacity. This effect is likely to be slow-burning over the coming 10-15 years and linked to business growth plans and the emissions price.
There should be increased investment in distributed energy resources – small-scale and upwards – because wholesale prices will be higher (and more volatile) where the transmission network is constrained. Locally produced energy will become more valuable, particularly at peak times. This creates opportunities for battery storage to arbitrage wholesale price risk. Additionally, in such situations, Transpower could also contract DER to operate during peaks to defer transmission investments where that is efficient.
Basically, Transpower will be expected to set up a replacement for ACOT. There is a reasonable prospect individual distributors’ in growth areas will do the same.
Once the new TPM is in place, distributors will have to decide how best to allocate fixed annual charges among their customers. It is not clear how this will be done. Currently, a material proportion of transmission costs are recovered through variable distribution charges – the ‘peak’ part of distribution time-of-use charges typically reflects the RCPD charge.