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I don’t want to be negative …. but have you looked at electricity prices

The National Electricity Market (NEM) recorded its highest frequency of negative wholesale electricity intervals in the year of 2023.


Using South Australia as an example, in 2023 the wholesale electricity price was negative for a 25% of the time (34% during the December quarter last year!) and Victoria just under at 22%. For those who are not too familiar with the electricity market, this means for these periods, electricity generators paid electricity users (i.e., retailers and large industrial customers) for the right to dispatch.


Doesn’t make too much sense? Let us dive into the how’s and the whys of negative electricity pricing and its implications on generators and users.


Source: NEM Review


Negative prices 101

Generators bid to dispatch in the NEM on a five minutely basis and the bids are stacked from the cheapest to the most expensive. Bids can range from the market floor of -$1000/MWh to the ceiling of $17,500/MWh (July 2024). Subject to transmission constraints, generators with the cheapest bids are dispatched first, and the spot price is simply the bid price of the last marginal generator required to fill demand in that interval (price setter). The spot price will be negative if the price setter has a negative bid.

Why would generators bid negative?

Bids generally reflect the fuel cost to generate and the opportunity cost of not generating. The key drivers to the negative price bidding behaviour are as follows:

  • Merchant Renewables. Renewable generators have close to zero marginal cost of generation and earn revenue on both electricity and Large Generator Certificates (LGC).   Renewable generators will earn one LGC for each MWh of dispatch. LGCs are currently priced $40-$50 per unit/MWh thus it quite rational to bid a negative price as long as the negative electricity price is smaller than the value of the LGC.  Given the clustering of renewable generation patterns, renewable projects often end up competing with each other to be dispatched and, hence, will bid at minus LGC.

  • Electricity offtake. Most offtakes are structured as a contract for difference, where the offtake pays the generator a fixed offtake price on each MWh generated in exchange for receiving from the generator the wholesale market price for that generation.   In the absence of a special clause providing for different treatments for negative prices (which are quite common, see below), this incentivises the generator to bid the market floor (that is, minus $1,000) to ensure they are dispatched.

  • Minimum generation. Coal generators typically have to maintain a minimum level of generation to remain operating. To stay turned on, and be in a position to profit from evening prices, these generators must be dispatched to at least their minimum generation level, so will bid to the market floor on this level of generation to ensure this happens.  They will bid higher prices, reflecting coal and its opportunity cost, on output levels above their minimum generation level.


Why are negative prices becoming more frequent?

Negative prices usually arise when there is excess generation compared to load, and this is increasingly common due to the following:

  • Renewables growth. The biggest driver of this change is the renewable transition. Excess generation clustered around periods with good solar/wind resources usually lead to negative prices. The 15GW of new utility scale renewable capacity added between 2019 to 2023 is the key driver of the change to the pricing dynamics. Renewables accounted for 37% of electricity generated in 2023.

  • Falling operational demand.  The rise in rooftop solar means that many customers no longer need to buy from the grid in the middle of the day (or even become net exporters) this is reducing the volume of electricity that needs to be purchase from utility scale generation.

  • Strong green certificate prices. LGC prices have remained strong over the past few years.


Transition over time

Let’s take a look at what has happened to negative prices in the NEM over the past five years. The graphs below capture the change of negative price intervals over time - the x axis is the 24 hours of the day, and the y axis is the percentage of time in that hourly trading interval the price is negative in that year.

Source: NEM Review


Unsurprisingly the negative price interval rises and falls with the sunlight hours. It is clustered around noon when operational demand is at its lowest (thanks to rooftop solar). The bell curve actually mimics the solar irradiance curve quite closely.


The growth of negative price intervals has also been quite rapid. Over a period of five years, peak negative price percentage grew from 10% to 65% in South Australia. Despite NSW and QLD being the least affected states, they are also following the trajectory of SA and VIC at the current pace of renewable deployment.


Negative pricing by month of year

We’ve included a chart showing the five-year average of negative price intervals by month of year (colour coded by season – green is Spring, yellow is Summer and so on) in Victoria. Negative prices are most painfully felt in Spring (low load with good wind/solar), followed by Summer while they’re at their the lowest in Winter (high load low irradiance).


Source: NEM Review


How negative do they go?

The chart below shows the percentage of negative price interval by price band (green is between 0 to -50, yellow is between -50 to -100 and red is sub -100).


The majority of the negative spot prices are clustered around the $0 to -$50 band, which is roughly in line with the value of one LGC. This reflects the level merchant renewables are willing to bid down to secure the LGC value. For the windier states the prices below -$50 is also becoming quite frequent. Once LGC prices converge to zero we are expecting the level of negativity to reduce.

Source: NEM Review

What’s happening next?

Here’s a take on what this implies and what we think will happen over the next couple of years.


  • Batteries. The current price dynamics gives rise to plenty of opportunities for batteries to enter the market to take full advantage of negative charging costs. All else equal, this would reduce negative price intervals.   However, in the short-term, it seems likely that the ongoing growth of rooftop and utility scale solar will swamp the impact of batteries.

  • Merchant solar farms. In the short-term, the energy revenue of merchant solar farms will be increasingly impacted by negative prices, and LGC revenue will become a bigger share of revenue.

  • It will get worse before it gets better. With the continuous roll out of renewables ahead of expected coal generator shutdowns, you should expect a saw tooth pattern, with the frequency of negative prices increasing as more rooftop and utility scale renewables enter the system, with reversals (i.e., few negative prices) each time a coal plant closes.

  • The extent of negative prices should become less negative over time with a fall in the value of LGCs as we approach the end of the RET.

  • Offtake carve outs. Most PPAs include some form of special regime in respect of negative prices.   These can vary from a strict prohibition against dispatching when prices are negative, to excluding negative intervals from the PPA (so projects are effectively merchant as soon as prices become negative), to applying a spot price floor in contract for difference mechanisms.   It is important to recognise that very small wording changes can have very large implications and that not all PPAs are equal.


Ultimately it is important to understand that it is cheaper from a whole of system perspective to overbuild renewables – and have some spilled energy – than to size storage such that every MWh that is generated is able to be stored.  Given this, a meaningful level of negative price intervals is an inherent part of the system.  That is, negative prices are a feature and not a bug!


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