Inherent in an electricity market like the NEM is its ever-changing landscape. Contributors to these changes may be government-driven policies, evolving market dynamics caused by external factors like a global pandemic, a worldwide rise in fuel prices, and even changes in the market structure itself. As cliché as it may be, the only constant in life is change, and adaptability plays an important role, especially for the participants in the electricity market.
Market participants’ trading strategies in the spot market play a key role in shaping the landscape of an electricity market. Though trading strategies evolve, their primary objectives remain – revenue sufficiency. Day-ahead to week-ahead price forecasts are very important sources of information for revenue maximisation, especially for energy-constrained generators like battery and hydroelectric power plants. Real-time monitoring is also as important.
In this Chart of the week, we analyse the changes in bid strategies of scheduled generators by comparing the difference in offered volumes at certain price ranges between 2022 and 2021 across different months. Positive values show that offers in 2022 are higher than in 2021, while negatives show the opposite. We’ll explore how NEM participants have adapted their trading strategies to changes brought about by an increase in fuel prices and market settlement structure. The top chart of Figure 1 is an analysis of fossil fuel plants, while the one at the bottom is for non-fossil fuel plants (solar, wind, batteries, and hydro).
For fossil fuel plants, a comparison of 2022 to 2021 offer quantities allocation shows the movement of significant volumes (averaging 2500 MW) from the $30/MWh to $50/MWh range. While for the first quarter of 2022, we can see significant volumes (averaging 1500 MW) moved from $50/MWh to $100/MWh, that was not the case as the months progressed, wherein offer quantities are allocated to 100 $/MWh to 1,000 $MWh. This can be attributed to the rise in fossil fuel prices compared to the same time last year. Spot prices for coal haven’t gone back since they started going up from around US$85-86/MT in January-February 2021 to ~ US$440/MT this month. These spot prices however don’t completely flow through electricity prices due to factors like the presence of long-term contracts. The same can be said for domestic gas prices, which were not spared from the effects of the ongoing war in Ukraine. The increase in the price of these fossil fuels, coal and gas, has driven changes in the trading strategy of the generator participants using those fuel types.
We can see allocation increase in the highest price range bucket $10,000/MWh to $16,000/MWh in the month of June, which also happens to be the month the market was suspended. In August, most of the capacities moved away to the lower price ranges, going from $100/MWh to $1,000/MWh and $10,000/MWh to $16,000/MWh. Fewer changes in offered volumes from 2021 to 2022 are also seen for August compared to June and July.
The implementation of 5-minute settlement on 1 October 2021 also brought about changes in bidding strategy for non-fossil fuel plants, as evident on the bottom chart of Figure 1, where there is a significant movement of offered quantities away from -1,000 $/MWh to -100 $/MWh. Moving these quantities to near 0 $/MWh was the chosen step as the growth in VRE capacity in the market means that they are increasingly having influence over the price at times compared to historically, where they would be price-takers. Therefore, we see VRE rebidding from -$1,000 to a price point closer to their willingness to generate – a trend we anticipate continuing.
The price for which fossil generators bids is dependent on their fuel costs. If fuel prices do reduce towards historical trends, then we could see reduced offers (and, by extension, prices) from fossil generators. However, the impact of an increase in fuel prices can also be tempered with the increased deployment of VRE, which offsets the need to utilise fossil generation in the first place.
