Will negative price risk increase following changes to dispatch obligations under the National Electricity Rules?

By Kate Axup, Danielle Jones, Luisa Colosimo

Increased exposure to negative price risk 5 min read

Semi-scheduled generators, such as wind and solar farms, will face increased exposure to negative price risk following a new rule made by the Australian Energy Market Commission (the AEMC) that means those generators will have less flexibility to 'turn down' their generation facilities when the spot price falls below zero.

Key takeaways

  • Currently, semi-scheduled generators can curtail generation without a valid rebid or an updated dispatch instruction, meaning 'turning down' during negative price periods can be done quickly, on a unilateral basis and without risk of penalty.
  • From 12 April 2021, semi-scheduled generators will be required to comply with the MW dispatch level contained in their dispatch instructions unless there is a change in the availability of the underlying energy source.
  • Negative price risk allocation under existing PPAs and PPAs under negotiation may need to be revisited, as the new rule changes the generally accepted position that a generator has flexibility to manage its exposure to negative spot prices and therefore can take negative price risk under PPAs.

What is changing?

On 11 March 2021 the AEMC made a final determination and final rule regarding dispatch obligations for semi-scheduled generators, in an effort to regulate generator curtailment in response to negative price intervals. The new rule will come into effect on 12 April 2021.

In particular, the new rule requires semi-scheduled generators to comply with the MW dispatch level contained in each dispatch instruction it receives – with the exception being  a variation due to a change in the availability of the underlying energy source. This effectively means that semi-scheduled generators will be restricted from curtailing generation without a valid rebid or an updated dispatch instruction.

This is not the case now, where:

  1. dispatch levels for semi-scheduled generators are only estimates of the active power to be sent out by the end of the relevant dispatch interval (and generators are able to generate more, or less, than the estimate); and
  2. during semi-dispatch intervals, generators are able to generate at any level up to (but not beyond) their dispatch cap.

After 12 April 2021, if the forecast negative price period changes after a dispatch offer has been submitted and a dispatch instruction received, a generator could rebid in order to manage its exposure to the change in the forecast price. In rebidding, the National Electricity Rules require the generator to provide a specific reason for the rebid. There is limited guidance in the National Electricity Rules as to what constitutes a valid reason to vary a dispatch offer and it is possible that an unexpected change to the forecast spot price would qualify as a reason for a rebid. However, such rebidding behaviour seems to be contrary to the stated purpose of the new rule being to regulate generator curtailment in response to negative price periods.

A rebidding generator will also need to wait for a revised dispatch instruction to be received – during which period they may be exposed to a negative spot price. Not only will generators have to adapt current dispatch and bid behaviour to align with this rule change, but this may also impact how parties are able to respond to, and mitigate, negative price risk under existing PPA arrangements. In any event, the additional reporting requirements associated with rebids, the risk of civil penalty for making false or misleading bids and the requirement for AEMO to accept the rebid before the generator can 'turn down' makes managing negative price risk more difficult for generators.

'Market' risk allocation for negative price periods in PPAs

In PPAs these days, it is common for negative price risk to be dealt with in one of the following ways:

  • The parties agree a floor on the spot price – this floor is often set at $0/MWh – which means the buyer is protected from negative price exposure. In these circumstances, it is standard for the seller to be provided with an express right to elect not to generate during negative price periods, and there are usually express carve outs for negative price periods from the seller's minimum generation obligations and obligations to maximise generation from the facility. In this way, while the seller takes negative price risk, it is in a position under the PPA to manage that risk.
  • The parties agree to a 'turn down' mechanism, where the buyer can direct the seller to curtail generation during periods of forecast negative pricing in exchange for the buyer paying a 'turn down payment'. In these circumstances, the seller is usually given relief from its minimum generation obligations for any periods affected by a buyer turn down instruction.

In both of the scenarios above, the parties rely on an ability to curtail generation as a legitimate means of managing negative price risk exposure. Indeed, the final rule determination from the AEMC acknowledges that many generators have invested in automatic dispatch systems to automatically reduce generation in response to forecast negative price periods. With this ability now impacted by the impending rule change, these PPA provisions may no longer operate as intended, resulting in either the seller or the buyer (depending on the scenario above) bearing more negative price exposure than originally envisioned.  

Actions you can take now

  • PPA counterparties – review the terms of your PPA and consider how negative price risk has been allocated and whether the change in law clause provides any assistance in terms of offering relief or a means to renegotiate the current negative price provisions.
  • Facility owners and operators – review dispatch and bid settings, particularly in relation to automatic dispatch systems that automatically reduce generation in response to a forecast negative price period.

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