On 18 August 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.
The seeds of the crisis were sown with international events months earlier, at the end of the pandemic and the start of the Ukraine war, spiralling into a perfect storm of bad luck by June. And, just when the industry needed them the most, the market rules failed it.
A price capping regime, conceived for different circumstances, greatly inflamed an already tight situation and forced AEMO to suspend the market. Many of the systems used to manage an extremely complex market became dysfunctional and whilst AEMO did its best to work around them, there were times that, as a result, 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.
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.
We take a look.
The Build Up
Dramatic rallies in east-coast natural gas and export quality black coal due to international factors began late in 2021 and reached a zenith by winter 2022 (see figures 1 and 2). For much of the winter New South Wales and Victorian gas markets operated under administered price caps. These are well covered in AEMO’s earlier Quarterly Energy Dynamics Q1 and Q2 reports.
Figure 1: Gas Price Rally
Source: STTM data
Figure 2: Coal Price Rally
Source: AEMO QED Q2 2022 Report
Generators have long-term contracts for part of their fuel supply but are not immune to these price fluctuations. Following years of low electricity prices and declining output, generators have sensibly 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, at the margin at least, exposed to these unprecedented prices, and, consistent with the market design, reflected it in their bids.
Spot electricity prices therefore followed the fuel prices up, also to unprecedented levels. This does not mean, of course, that generators were necessarily making large profits. Indeed, many were incurring losses as their electricity sales had been forward contracted at much lower prices. It is analogous to those builders who contracted to build houses at 2021 prices, but now face 2022 materials costs.
By May 2022, several unrelated physical circumstances conspired to make the situation critical.
The level of outages in coal plant has been much discussed publicly. These were certainly greater than desirable, but as shown in figure 3, out of an installed capacity of over 23,000 MW, they were less severe than some of the commentary implied.
Figure 3: Coal Plant Outages
Source: AEMO QED Q2 2022 Report
As with all complex problems the devil is in the detail. What’s not shown in the figures is the fact that the forced outages tended to be in the plants with “mine-mouth” coal, meaning a greater reliance was placed on those plants competing for fuel supply with exporters.
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 but experienced its usual feast and famine cycles which AEMO show on page 21.
Early winter was unusually cold across the entire NEM, with new winter demand records set in Queensland. Even though peaks are lower, customers demand more energy over time in winter than summer. And, very unusually for the NEM, it was energy, rather than capacity, that was in short supply during the crisis.
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. Adam Smith’s invisible hand operated to great effect.
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 the 12th. 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:
Its other important features exacerbating this crisis were:
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 recognises a higher opportunity cost by rebidding higher into the market, which results in the dispatch process finding another energy source that is less energy limited. 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 their energy exhausting, which, were it to occur, would lead to an even more serious crisis. Instead, they had no choice but to withdraw from the dispatch process 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.
AEMO’s report provides an insight into the vast complexity of manually rationing energy on page 24:
“Reduced coal production at local mines and reduced deliveries from remote mines meant that a number of major power stations in New South Wales experienced very low coal stocks and implemented energy limits for their generation. The daily energy limits at these stations varied depending upon the levels of coal stockpiles and daily deliveries, which were frequently unpredictable. Raising the energy limit for a given day could mean that a lower limit would be necessary for the following day, requiring dispatch decisions to be made based on anticipated power system conditions. For example, on one occasion AEMO scheduled additional energy-limited coal generation when supply was tight due to lower forecast wind generation for the following day, on the basis that the forecast wind generation was significantly higher for the day after that.”
And on page 44:
“In essence dispatch was moving from being a market-based process – with directions only where needed to address specific issues – to a centralised volumetric scheduling exercise with market systems being increasingly used to implement this scheduling rather than determining least-cost economic dispatch and associated spot market prices as contemplated in the National Electricity Rules.”
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. As AEMO notes on page 27:
“..the forecast LOR conditions published…were not necessarily representative of reserve conditions, given that AEMO was manually directing generation…”
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 having entered APC, the market was trapped without a way to exit it.
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 two scenarios:
It 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. Indeed, the number of directions continued to increase (figure 4), whilst the issues (1) and (2) above continued. 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.
Figure 4: Total net directed capacity in the NEM
Source: Report, page 31
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 the 23 June 2022.
Chapter 6 of the report refers to management of transmission limits, particularly the flow on the Queensland to New South Wales interconnector which exceeded its secure limit for about an hour on 13 June. This is a breach of the Rules which state that AEMO must restore a secure state within 30 minutes, even if that requires interrupting some customers.
This rule is in place for good reason. When operating insecure, the next major contingency could lead to a major power system disruption, such as a black system. Fortunately, no such contingency occurred.
This was perhaps the most serious outworking of the crisis. There was no physical event that should have driven the power system insecure, and on any other day the flow would have been managed comfortably. The exceedance arose solely because of the inaccuracy of having to rely on the clunky process of manual directions.
Thus, the integrity of the underlying power system was placed at serious risk purely because of a flaw in the rules of the market that sits upon it.
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 that it had urgently 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.
As shown in figure 4, this letter had no effect as even more capacity was subsequently withdrawn and AEMO directions increased, not reduced. This was, of course, because the withdrawal was necessitated by more acute reasons than compensation.
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 despite the AEC’s attempts to correct the public record, 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 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 returned, weather became milder 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. This is not to say it would have removed all risk - arguably the conditions were so extreme it may have required an even higher price to clear.
There are many lessons to be learned from this event. Most important however 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.
Consultations are underway for the setting of the default market offers in 2024. Both the Australian Energy Regulator (AER) and the Essential Services Commission (ESC) in Victoria and have released early papers outlining their key areas of focus. In comparing the two approaches, the AER appears to be undergoing a more detailed review, whereas the ESC seems to be more settled in its methodology overall. We take a look at the approaches being undertaken.
The development and construction of new transmission where economically justified is critical for the energy transition and it needs to be delivered in a timely and efficient manner. Several rule change proposals highlighting concerns about the TNSPs’ ability to raise the necessary finance to fund construction on terms that maintain a BBB+ credit rating. We take a look at the issue and consider whether there might be other workable approaches to deliver the transmission the transition requires.
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