AEMO market suspension report: Anatomy of a crisis

Ben Skinner is the General Manager, Policy at the Australian Energy Council. He examines AEMO’s report on the 2022 market suspension. Early in the crisis it was unclear exactly what was occurring, and some misinformed commentary pre-emptively blamed generator bidding behaviour, which was then repeated by mainstream media and politicians, unfairly tarnishing the industry’s image. AEMO’s report shows that the crisis was far more complex, and, if blame can be laid anywhere, it rests in rules written two decades earlier.

The Australian Energy Market Operator (AEMO) published its much-anticipated statutory report on the National Electricity Market (NEM) events in the fortnight between 10 and 24 June 2022. While the terms “crisis” and “unprecedented” are over-used in industry commentary, the scale of the events portrayed by the report most definitely justify them.

In a previous article, Energy Insights identified some of the factors that spiralled into a perfect storm of bad luck by June. Then, just when the industry needed them the most, the market rules failed it.

A price capping regime greatly inflamed an already tight situation and forced AEMO to suspend the market. Many of the systems used to manage the extremely complex market became dysfunctional and whilst AEMO did its best to work around them, there were times that the power system itself was at much more risk than it needed to be. Through great efforts by AEMO and the industry, no customers were blacked out, but a disaster could easily have ensued.

The Build Up

Generators were impacted by price rises in east-coast natural gas and export quality black coal which began late in 2021 and peaked in winter 2022. Following years of low electricity prices and declining output, generators have been taking progressively more spot fuel exposure over time. In the conditions through winter 2022, a great number of black coal and gas generators were exposed to unprecedented fuel prices.

Spot electricity prices therefore followed the fuel prices up. Many generators were incurring losses as their electricity sales had been forward contracted at much lower prices. By May 2022, several unrelated physical circumstances conspired to make the situation critical.

Outages in coal plants can be a bit of a red herring. What was significant during that period is that the forced outages tended to be in the plants with “mine-mouth” coal, meaning generators that compete with exporters were the ones being relied on to produce power.

This issue was exacerbated by wet conditions in Queensland slowing the delivery of coal. Wet conditions in New South Wales also limited hydro’s downstream releases.

Being the solstice month, large-scale and rooftop solar was at its annual minimum contribution. Wind output averages somewhat lower in Autumn and early Winter.

Early winter was unusually cold across the entire NEM, with new winter demand records set in Queensland. Though peaks are lower, customers demand more energy over time in winter than summer.

But, until 12 June, the market performed remarkably well. The bidding and dispatch process, its price incentives and AEMO’s forecasting tools assisted countless decentralised decisions. They produced an outcome better than any centrally controlled power system could achieve, and no customers were interrupted.

The Administered Price Cap

With a combination of coal plant outages, fuel shortages, high demand and transmission outages, Queensland electricity prices reached very high and sustained levels in the lead up to the weekend of 11-12 June. These were enough to trigger the Cumulative Price Threshold (CPT) at 1850 hrs on 12 June. The CPT operates when a region’s average price exceeds $674/MWh over a rolling week, equivalent to 7.5 hours of the Market Price Cap (MPC) of $15,500/MWh.

The CPT is the NEM’s “force majeure” mechanism, unchanged since it was conceived 20 years earlier to limit extreme financial risk from summer heatwaves. Designers took the view that a maximum 7.5 hours of MPC revenues during a heatwave were enough to provide an adequate signal for building new capacity, but that after this, further wealth transfers would represent an unnecessary windfall. Thus, the market would be capped after CPT to a level just sufficient to cover the Short-Run-Marginal-Cost (SRMC) of most generators.

However, the CPT/Administered Price Cap (APC) regime had two very serious shortcomings when used in this crisis:
1. The regime was envisaged to operate in short, sharp, heatwaves. There was no contemplation of whether APC could sustainably operate over an extended period.
2. The APC still retains a nominal value of $300/MWh reset in 2008 which was above the great majority of SRMCs at the time. It was not indexed for inflation, a serious oversight in hindsight. A compensation regime exists, but the design assumes this is rarely called upon.

Other important features exacerbating this crisis were:
3. Even though the CPT is triggered in one region, the APC applies to other regions exporting to it through regulated interconnectors. This meant all regions except Tasmania were effectively subject to the APC from 12 June.
4. To release the APC, the pre-capped average price must first fall below the CPT. However, the unintended effects of the APC itself forced pre-capped prices continuously up to the MPC in all regions. Thus, the market was trapped in loop where the CPT/APC could never be released.

Rationing Limited Energy

The APC destroyed the market’s ability to self-manage the winter energy shortage. Normally, when a generator’s fuel is constrained, it rebids higher in the market, which results in the dispatch process finding another energy source. This process works remarkably well but requires the market to have freedom to realise progressively higher prices, and for generators to bid and set prices at least as high as the highest SRMC that is not subject to an energy limit.

However, after 1850 hrs on 12 June, generators found the process could not work. No matter how high they rebid, they found themselves dispatched to an unsustainably high level of output. Ultimately, they had no choice but to withdraw the capacity to stop exhausting their energy, and leave it to AEMO to determine when to dispatch them, via the direction power.

Thus, the whole dispatch process was replaced with manual central decision-making by AEMO. Thankfully, as the report states, generators worked closely with AEMO through the difficult period, and quite remarkably, maintained reliable supply to customers.

Market Suspension

Despite these valiant efforts, the 67 hours of the APC were messy on many fronts:

1. The withdrawal of capacity meant that the normal process for forecasting and publishing reserve margins became dysfunctional. Not knowing that the “withdrawn” capacity was actually operational, these systems forecast spurious LOR3 notices (expected load shedding) causing extreme consternation in stakeholders.

2. “Overconstrained dispatch” (OCD) intervals frequently occurred. This means the dispatch engine is unable to find a feasible dispatch solution without violating a constraint. This could mean the power system is being operated insecurely.

3. As discussed earlier, the withdrawn capacity resulted in uncapped prices remaining continuously at the MPC, meaning that the market was trapped without a way to exit APC.

AEMO decided then to take the extraordinary step of invoking a Market Suspension at 1405 hrs on 15 June. This concept was originally conceived for a major IT failure, or a system black or other very large physical disruption. It was last invoked in the September 2016 South Australian event.

A Market Suspension has the effect of settling under the “market pricing” schedule, rather than a dispatch price capped at APC. This schedule is the average of 4 previous week’s prices, but is also capped at $300/MWh. If they remain at all functional, AEMO may still use their normal dispatch systems, which they attempted to do.

AEMO hoped that the suspension would resolve these problems, but it didn’t. In hindsight, this is not surprising, because the suspension didn’t resolve the underlying problem, the inability of any price-capped dispatch process to ration energy.

But the suspension had one major benefit that made it well worthwhile. Its arcane rules result in the CPT being determined on the market suspension price, which were well below the $674/MWh average. This meant that, after a week of suspension, the rules permitted the market to restart without the burden that had brought it to its knees: the APC.

Physical conditions had also somewhat eased (plant returns, milder weather) and the market was successfully restarted on 23 June 2022.

External Perceptions

In the initial hours of the APC, there was little understanding, even within the market bodies, of exactly what was occurring and why generators were withdrawing capacity from the dispatch process. On 14 June the Australian Energy Regulator (AER) published a letter sent to all generators. The letter speculated the withdrawal may have been motivated by generators seeking to maximise compensation payments, and, in a threatening tone, implied they should immediately re-present this capacity.

This letter had no effect as even more capacity was subsequently withdrawn and AEMO directions increased.

The media and politicians’ interpretation of the letter was hardly surprising: a regulator blaming the crisis on generator gaming. This commentary went as high as Prime Minister Albanese, who said “There was a bit of gaming going on of the system, which is why AEMO used its tools at its disposal to intervene, so we do have these short-term issues.”

As more facts came to light over subsequent days, the AER did not repeat this misunderstanding, however by then the damage to the industry’s reputation was done. This unfortunate episode was an unhelpful distraction during the crisis and shows the importance of care in market bodies’ commentary.

The Aftermath

The CPT came close to being retriggered on 4 July, and, if it had, another market suspension would likely have been required. Since then, underlying physical conditions have progressively eased as plant generation has stabilised and solar generation increased.

Alinta Energy has proposed an urgent rule change to lift the APC to $600/MWh for one year. If made, this would likely be in place in time for the upcoming summer, a season where CPT’s have previously occurred.

Were the extreme events of June 2022 to be repeated, a doubled APC would give the market more headroom to cover high fuel costs and to self-ration its limited energy supply.

The most important lesson to be learned from this event is how obscure and rarely used mechanisms such as the CPT/APC regime need to be regularly reviewed for current conditions. This includes considering current industry costs, and role-playing different scenarios, including those that have not occurred previously.

Perhaps the greatest indictment from this event is that market rules were so out of date that they actually placed the power grid at risk of major disruption.