One of the big mysteries of the past few months in Australia’s complex electricity markets has been the performance and decisions of some of the big coal and hydro generators in Queensland – both coal and hydro.
Many observers have been stumped as to why, in the depth of recent negative pricing events that were caused by a combination of lots of solar, low demand and network constraints capping exports to the south – some coal generators actually increased generation, and the biggest “battery” in the state was hardly used to soak up the excess supply.
At one stage in September, as RenewEconomy reported at the time, most solar farms in Queensland turned off “en masse” in response to the negative prices, while coal generation increased and the 570MW pumped hydro facility stayed idle.
(See Solar farms switch off en masse as coal plants flex their muscle in Queensland)
Some light was shed on this situation earlier this week, when the Australian Energy Market Operator noted that Wivenhoe had only “pumped” on 18 per cent of the occasions that prices went negative in the September quarter.
It blamed this on operational and environmental issues, and also on “commercial considerations” – likely to refer to how its former owner CS Energy managed its predominantly coal portfolio.
More light has been shed by the Australian Energy Regulator, in its own quarterly report released on Friday, which suggested that coal generators had been encouraged to boost capacity even during negative prices because of an effective bonus pool in frequency and ancillary control markets.
It is often forgotten that the spot price of electricity is just one of dozens of different markets operating within the National Electricy Market, with many of the additions focusing on FCAS.
AEMO has recently announced that it will make changes to the amount of FCAS is wants on standby in the market, partly because it is concerned that not enough FCAS has been available, particularly in markets such as Queensland where there are no big batteries, little demand response, and where coal generators have been relaxing their “governor” controls, which affects their ability to provide FCAS.
This issue was brought to its attention in the big outages that followed a lighning strike on the main link between Queensland and NSW on August 25 last year.
It created such a ruction in the grid that Queensland and South Australia separated, outages swept across NSW, Victoria and Tasmania, and while South Australia – thanks to the Tesla battery – had no problems, the lack of FCAS response from Queensland coal generators left that state in a perilous position.
It was an event that sent the industry bananas with frustration.
By changing the rules, AEMO has effectively increased the amount of mainland base “regulation” FCAS volumes by 50 MW in March, and a further 20 MW in April and 20 MW in May 2019, or a total of 90MW, due to deteriorating frequency performance.
It has also increased the amount of “contingency” FCAS by around 100MW, and will likely do so again in the second phase of its proposed changes. And while the presence of the Tesla big battery has punctured the FCAS cartel in South Australia – where the gas markets could charge what they liked when constraints were imposed – there are no big batteries in the sunshine state.
(Regulation FCAS refers to small changes of supply, and contingency FCAS looks to manage large changes in supply, in the event, for instance, of a network fault or a sudden generator or load outage).
This has led to some bizarre outcomes in the market, and incentives to coal generators to increase generation during negative pricing events, when normally they would be seeking to ramp down. Or, if they had a pumped hydro facility or battery storage, to switch those facilities on.
As the AER noted:
“We have also observed participants rebidding capacity to low prices in Queensland at the time of negative prices, citing ‘FCAS/Energy co-optimisation’ as the reason.
“Participants who offer capacity into the FCAS markets in Queensland are mainly coal-fired generators. When the price of energy is negative these generators may have incentives to increase dispatch in FCAS markets where the prices may be higher.”
It cites the example of September 4, 2019, when the price for some lower services was above $300/MWh at the time that energy prices were negative, so delivering enough incentives for coal generators to lift their output, and effectively chase the solar and wind farms out of the market.
(The coal generators could dominate the FCAS market because the network constraints effectively shut battery competitors elsewhere out of that market).
This is just part of the problems with FCAS at the moment, a subject we will jump back into next week.
But it was also interesting to note – just for the record – that while increased generation of wind and solar, and network constraints that limit exports – have been blamed for negative pricing events, it is the coal generators who actually bid most of their capacity below zero.
The AER says negative pricing events are a normal part of the market, and coal generators in Queensland bid 71 per cent of their capacity at negative during the September quarter, which meant that for some of the time there was enough negatively prices coal capacity to meet demand.
Why? Because much coal capacity is unable to be flexible about output, and would prefer to endure periods of negative prices to avoid greater costs, or to meet contracted loads.
So coal generators don’t switch off, while solar and wind farms and gas generators do, unless directed otherwise. And batteries and pumped hydro should charge and pump.
