While the details are more than some might care for, I'm new to the energy delivery business and was fascinated by the potential for manipulation from the parties involved, from suppliers to government regulators. Because profit are based on supply failure, I can see how "unexpected failures" would be more frequent and, perhaps, an alternative would be to incentivize non failures. https://flip.it/p7WIcd Big batteries lead charge in high priced grid events, as coal and gas plants struggle to keep pace Giles Parkinson 15 May 2025 Two of Austraia’s newest big battery projects have been named as responsible for leading the bidding in some of the highest priced events in Australia’s main grid in the March quarter, as coal and gas plants struggled to keep pace with changes in the five-minute market. High priced events – when the wholesale price can rise to the market cap of $17,500/MWh – matter because they are a key component of consumer bills, given their outsize influence on the average wholesale price over a quarter. In the March quarter, according to the Australian Energy Regulator, there were just 11 high priced events – defined as prices going above $5,000 a megawatt hour (MWh), compared to 28 in the same quarter a year ago. The AER goes into some detail about the cause of the events, and who bid what, when and why. It identifies two new big batteries – Neoen’s Western Downs in Queensland and AGL’s Torrens Island in South Australia – as being responsible for some of the highest priced events when prices were sent to or near the market cap. Its summary of the document identifies high summer demand, low wind conditions and network issues as the primary causes of the high prices. Curiously, the written summary of the report – the bit that most people read – makes no mention of the multiple and persistent unplanned coal fired power station units that affected capacity in Queensland and NSW, although they are mentioned in a table. And its focus on low wind output in Victoria and South Australia is distorted by the fact that it assumes – when giving its percentage output – that the biggest wind projects in those states – Golden Plains (753 MW) and Goyder South (413 MW) – are operating at full capacity, which they are clearly not. They are still working through their commissioning process. Be that as it may, the report offers some fascinating insights into the way the market operates, and some of the restrictions that help to contribute to high priced events. On nine out of the 11 high priced events, network outages played a key role, preventing up to 2.5 GW of low priced capacity reaching its market. Most of these network outages were in NSW, and more than half of these were unplanned. In some instances, the blockages were enforced by the Australian Energy Market Operator. On three of the high priced event days, AEMO decided – in response to network limitations – to restrict the flow of negatively-priced generation (mostly hydro) to maintain system security. The AER says these restrictions caused high prices. One of the few high priced events that occurred in the middle of the day – rather than the evening peak – was on January 15, when around 2,000 MW of rooftop PV was lost due to cloudy conditions, and prices spiked to $17,500/MWh. The AER notes that during the high prices, around 800 MW of gas capacity could not start up quickly enough, and a further 800 MW from units already running could also not ramp up quickly enough. And neither could another 820 MW of coal fired capacity at the Vales Point, Eraring and Mt Piper coal fired power stations. If these coal and gas plants had been able to react quickly enough, the AER says there would have been enough capacity to stop the high prices from occurring. Sometimes, there are technical issues which leads capacity to be withdrawn just before the high priced events. These can be milling issues, or “temperature” issues, such as those that occurred in Queensland on January 22 at the Milmerran and Gladstone Plants, taking away a combined 792 MW of low priced capacity just when it was needed. Added to the 710 MW of capacity lost due to planned and unplanned outages at Gladstone and Tarong coal generators, and the 500 MW lost from restrictions on the main connector to NSW, this created the perfect conditions for the remaining generators to bid the market to the top. Which they duly did, and the AER notes that the bidding was led by Neoen’s Western Downs battery, which shifted 192 MW from low to high prices “due to changes in its state of charge,” setting the price from 6.05 pm to 6.15 pm and 7.25 pm to 7.30 pm. On february 1 in South Australia, network outages and low wind output meant that between 130 MW and 190 MW of high priced capacity was needed to meet demand, and this came from rebidding for commercial reason. Just before 6pm, AGL Energy shifted 90 MWfrom $138 per MWh to the market cap of $17,500 per MWh at the Torrens Island gas plant, and 65 MW from under $215 per MWh to above $9,625 per MWh at the Torrens Island battery. The AER says the Torrens Island battery set the price for all six high-priced intervals. In February 3, with similar conditions, AGL Energy removed 65 MW of low-priced capacity at Torrens Island B gas plant, the Dalrymple North battery and Mckay power station due to “plant failure.”. It shifted 142 MW of capacity from low to high prices at Barker Inlet and Torrens Island B power stations due to a change in forecast prices. The AER says these rebids contributed to the high prices at 7.05 pm and 7.10 pm, while Neoen shifted 80 MW from low to high prices in a late rebid at the Hornsdale Battery due to “updated state of charge,” which set the price for 7.15 pm. On February 5, in NSW, multiple unplanned network outages and the unplanned loss of 1.4 GW of capacity from the Eraring and Bayswater coal fired power stations left the market exposed once again, and the prices went above $5,000/MWh for the 5.30pm 30-minute interval. Back in South Australia, on February 12, more network limitations and low wind – and restrictions on the Lake Bonney wind and battery complex – left the market exposed. The AER says between 48 MW and 120 MW of high price capacity was needed to meet demand during the high prices. “Rebidding for technical reasons contributed to both dispatch intervals where high-priced offers set the price,” it said. “AGL Energy removed 150 MW of low-priced capacity at Torrens Island Battery due to a change in unit capabilities.” And in NSW on March 15, high demand, lower wind output and yet more network limitations, left the state needing between 5 MW and 133 MW of high-priced capacity to meet demand. The AER says AGL Energy withdrew between 65 MW and 123 MW of low-priced capacity, impacting the 5.35 pm, 5.55 pm and 6.20 pm high prices. Most of this rebidding occurred at Bayswater power station due to “milling and feeder issues”, but 13 MW was withdrawn at Broken Hill battery due to a “capability change”, which impacted the 6.20 pm high price. The AER says the combined effect of these high priced events was to drive up the quarterly volume-weighted average price by $16/MWh in South Australia, $14/MWh in Queensland, $8/MWh in NSW, and $3/MWh in Victoria. But this impact was offset by the growing number of negative price events, which were 30 per cent more common than in the same period a year earlier, and a record number in NSW and Queensland. Compared to Q1 2024, there were 30% more negative 30-minute prices in the NEM. There was a record number of negative prices in NSW, while in Queensland the number of negative prices was a record for Q1.17 Despite more negative prices, their impact on the quarterly VWA price was minimal due to the negative prices being closer to zero than in previous quarters (e.g. -$50 prices compared to -$300). The impact of negative prices was largest in South Australia and Victoria, reducing the quarterly VWA price by $8 per MWh and $6 per MWh, respectively. That meant that in Victoria, the impact of negative prices more than offset those of high priced events. The AER says the impact of negative prices would have been greater, but for the fact that the negative prices were closer to zero (minus $50/MWh rather than $300/MWh) than they had been previously. That probably has something to do with the price of LGCs for renewables. All Rights Reserved
Victoria and South Australia are two basket case states. Vic is always up to its neck with political dramas involving their Premiers. SA is a state where Adelaide Capital is called the City of Churches, everyone is broke there, gummint does fuk all other than sit on hands, regarding mining, they cannot get their shit together. I have a policy, I never buy stocks in companies in SA.
Reminds me of the energy supply "issues" that Enron energy traders used to exploit/create to move the price of around at will