Editor’s Pick | Real-time pricing approved for NZ spot market

This article was originally published on 31 July 2019 in Energy:2030.

The New Zealand Electricity Authority (EA) has decided to settle the spot market on prices determined in real-time (RTP).

In its decision, issued on 27 June, the EA said this is the largest change to the wholesale spot market since its inception in 1996 and will make the spot market simpler, as prices will now be driven directly by live conditions on the power system. It follows a consultation in 2017 on the design elements, and a further consultation in March this year on specific elements, including a “dispatch lite” process for smaller generators and suppliers.

The reform targets two problems with the current arrangements:

  • spot prices are first calculated the day after real-time using different inputs, with final prices confirmed the day after that, and
  • spot prices published up to and during real-time are only indicative such that large differences can arise, especially when the power system is under stress.

This means that spot prices are uncertain, making it harder for parties to make efficient real-time decisions on electricity purchases or sales.

Under the revised arrangements, dispatch prices for energy and reserve will be derived from the marginal generator offer or dispatchable demand bid each time the system operator issues new dispatch instructions, instead of a more “idealised” dispatch calculated in hindsight. The interim price for a trading period will be the time-weighted average of the set of dispatch prices during each 30-minute trading period for each node, and the price is expected to be issued seconds after the trading period ends.

The EA considered, but rejected, volume rather than time-weighting the prices, as this could cause substantial price differences between reference nodes and those in the surrounding electrical region in otherwise similar conditions. This could become problematic for risk management contracts such as contracts for difference and financial transmission rights, which are tradeable in NZ’s nodal pricing system.

The EA said generators may not need to change their systems substantially, as offering and dispatch are broadly the same as currently, except for reoffering within a trading period. However, dispatchable demand participants will need to establish an interface to the system operator’s dispatch service, to receive electronic dispatch instructions in real-time, and update their processes to use those dispatch instructions.

Dispatch lite, available for generators up to 30MW and demand (no maximum capacity but it must be approved by the system operator), will be implemented. The differences from the standard arrangements are that this capacity can refuse dispatch instructions, can withdraw from the dispatch process and become a price taker, but does not receive constrained on or off payments.

RTP will be implemented in stages over the next four years, and the EA stressed ongoing dialogue between it, service providers and participants will be vital.

Once RTP goes live in late 2022, the EA expects it will produce Net Present Value benefits of NZD$50mn (£27mn) over 15 years under the base case assumptions, with upper and lower cases at NZD$95mn (£51.4mn) and NZD$15mn (£8.1mn), respectively.

The EA said more actionable and reliable prices send clearer signals for efficient long-term investment, and improved price signals will remove barriers and promote uptake of new technologies and business models.

This important and sensible reform is designed to make spot prices more actionable and efficient. It is also expected to enable more active participation of the demand-side. Issues around the reliability of indicative prices and ex-post adjustments are, of course, relevant in GB.

Electricity Authority

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