Fossil fuels are responsible for most greenhouse gas emissions. Electrification and new renewable generation is therefore critical to New Zealand achieving its climate change goals. 

Key takeaways

  • The new transmission pricing methodology (TPM) published by the Electricity Authority in April[1] contains provisions to address first mover disadvantage (FMD).

  • The FMD provisions in the TPM are intended to remove potential disincentives for the connection of new renewable generation and the electrification of load.


The TPM is the part of the Electricity Industry Participation Code that governs how Transpower (as grid owner) recovers its revenue from its customers (grid-connected generators, distributors and large consumers). Transpower’s maximum allowable revenue is set by the Commerce Commission. The TPM is about how Transpower’s revenue “pie” is sliced. The new TPM will come into effect on 1 April 2023.

FMD refers to commercial disadvantages early investors, in this case in renewable generation or electrification, may face relative to later ones. The TPM addresses both Type 1 and Type 2 FMD in relation to connection assets (the parts of the grid that connect specific customers, sometimes referred to as “spurs”).

Type 1 FMD

Often, Transpower agrees with a customer to build or upgrade a connection asset and the customer agrees to pay Transpower the capital cost of the work. This arrangement is recorded in an investment agreement between Transpower and the customer which sits outside the TPM.

Type 1 FMD arises because the customer who is party to the investment agreement (the first mover) will typically pay the entire capital cost under the agreement even if another customer later connects to the relevant connection asset. Type 1 FMD potentially creates an incentive to avoid being the first person to invest in renewable generation or electrification in an area, if the investment will require a new or upgraded connection asset.

The TPM addresses Type 1 FMD by imposing a charge on a customer who connects to a connection asset that was, or is being, paid for by another customer under an investment agreement. The charge is calculated to be an equitable contribution to the capital cost of the connection asset and is rebated off the first mover’s transmission charges.

Type 2 FMD

Grid investments exhibit significant economies of scale. Usually, incremental “just in time” grid investments are less efficient than grid investments with sufficient capacity to cater for future growth (anticipatory capacity).

Transpower may consider it efficient to invest in anticipatory connection capacity in an area well-suited for future renewable generation and/or electrification investment. An example might be provisioning for future connections by providing extra space or higher capacity common assets while building a connection for the first mover. Doing so may significantly reduce the time and cost of connecting other customers later.

Type 2 FMD arises because a customer connecting to a connection asset early, or already connected to it, (the first mover) will have to pay for both the capacity it needs and the anticipatory capacity in the connection asset, until later customers connect and share the cost (if they do). Type 2 FMD potentially creates an incentive to avoid connecting early to a connection asset with anticipatory capacity, or even to disconnect from it. The anticipatory connection capacity may deter the renewable generation and/or electrification investment it was built to cater for and encourage.

The TPM addresses Type 2 FMD by spreading the cost of anticipatory connection capacity across a wider set of customers than just those connected to the relevant connection asset. Spreading the cost also spreads the risk that the anticipatory connection capacity is not needed in future.

Half of the cost of the anticipatory connection capacity is spread across all customers through the asset component of connection charges. The other half is spread across the customers who are deemed to benefit from the anticipatory capacity. This will be a subset of customers comprising generators if the anticipatory connection capacity is expected to facilitate electrification or load customers (principally distributors and grid-connected consumers) if the anticipatory connection capacity is expected to facilitate renewable generation.

Renewable energy zones

Transpower has recently concluded its first round of consultation on potential renewable energy zones (REZs).[2] REZs are areas identified as particularly well-suited for renewable generation and/or electrification investment, but are remote from the grid backbone making connections relatively costly and difficult.

Transpower estimates there is around 11 GW of wind and solar generation that could be built in the next 30 years, with about 5 GW of it at the fringes of the grid where REZs could assist. Transpower has identified Northland as the first potential REZ location.

Transpower is considering what commercial and regulatory arrangements may be needed to get connection capacity into REZs. One option is to have collaborative investment agreements under which several interested parties team up to pay for the investment. This would effectively reduce the need to use the FMD mechanisms in the TPM for the investment.

Transpower’s REZ consultation closed in early April. Transpower plans to announce next steps in June or July 2022.

Residual charges

Another aspect of the new TPM with climate change implications is the approach to allocating residual charges.

Under the new TPM, part of Transpower’s revenue will be recovered through residual charges paid by load customers. Residual charges will be allocated based on gross load (that is, how much consumption is happening behind a point of connection to the grid, whether the electricity is coming from the grid or somewhere else).

Earlier versions of the proposed TPM included a step change in a load customer’s residual charge allocation when the customer, or a party indirectly connected to the grid through the customer, connected new large consuming plant or carried out a large upgrade of existing consuming plant. This is not a feature of the final TPM. Instead, the increase in the customer’s residual charge allocation will be lagged, and the customer’s full allocation for the new or upgraded plant will not accrue until around eight years after it is commissioned.

This will help the business cases for proposed electrification projects. 

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