In our November update, we discussed how forward contract prices were experiencing unprecedented volatility on a day-to-day basis despite much lower spot prices outcomes than originally anticipated by the market.
One of the key factors driving volatility in forward contract prices was continuing high fuel costs for generators and the expectation of a tight gas market in 2023.
With inflation globally and in Australia reaching levels well beyond the general annual target of 2% per annum, and with energy prices contributing a significant amount to bill inflation for household and businesses, the Australian government introduced a domestic coal and gas price cap to help curb energy costs. The caps are intended to reduce the marginal cost of generation for coal and gas generators who make up a significant amount of power supply in Australia, as well as reduce input costs for industrial consumers.
Typically, the forward power markets are proficient in pricing in regulatory risk. In the lead up to the announcement, 2023 and even 2024, contract prices decreased by almost a quarter as market participants started to price in the likelihood of regulatory intervention. When details of the intervention were introduced to Parliament on the 15th of December, contract prices further declined. This was likely in response to the price cap of $125/Tonne on coal, given coal generation makes up most of the power generation within the NEM.
A $125/Tonne coal price corresponds to a marginal generation cost of roughly 50 to 70 $/MWh.
It’s unclear if the temporary gas cap of $12/GJ has had an impact on forward electricity prices, given the gas cap only applies to 2023, and the contract price decreases in 2024 have been comparable to those in 2023.
Interestingly, international coal and gas prices have since declined from the highs sustained in November and December as winter heating demand in the Northern Hemisphere was much lower than anticipated. Further, China did not bounce back as quickly as expected post-lockdown, which again led to much lower demand for fuels.
While changes in forward contract prices do not immediately impact bills, typically a sustained high price level eventually translates to a higher retail default market offer (DMO) and higher commercial energy costs. In curbing forward contract prices, the wholesale component of power bills in 2023 and 2024 is trending much lower than pre-intervention.
While the domestic coal caps appear to have had a direct and immediate effect on forward electricity contract prices, their effect on the spot market has not been as clear cut.
Spot prices, on average, continued to decline across the NEM, as we moved through October and into 2023, continuing the downward trend following the extreme prices seen in the middle of 2022.
Charted here is the 7-day rolling average spot prices in Queensland, New South Wales, Victoria and South Australia, from the start of October last year, up until the end of the second week of February. Queensland and New South Wales prices have generally trended together, as have the Victoria and South Australian price. The more variability in the spot prices in the southern states reflects the greater proportion of wind generation in these regions – the higher the wind output, the lower prices, and vice versa.
As we can see, there was a general down trend across all regions, as we moved through to the holiday period at the end of the year. Prices remained at these lower levels until we rolled out of the holiday period, and into some strong summer heat, after a mild start to the year, which drove price volatility, particularly in Queensland and New South Wales.
However, prices remained well below the extremes of 2022, as we see from the dotted lines, which indicate the Calendar year 2022 average spot price, in each state.
So, what were some of the drivers of these trends in the spot price?
In the chart, we are looking at the 7-day rolling average of the Total, NEM-wide Demand, and generator available capacity.
We observe that, on average, demand trended down as we moved into the December period, with no real early summer heat to drive higher power usage. As we moved into 2023, strong summer heat, particularly in the northern states, saw demand surge higher, accounting for the surge in spot prices over this period. These were tempered somewhat by the greater levels of available generation capacity, which increased significantly, starting in early December, to levels well above those at the start of October.
To understand how some of this additional capacity contributed to put downward pressure on spot prices, we now turn our attention to some generator bidstacks.
We start with the combined bidstacks of the Queensland coal-fired generation fleet. This chart shows the daily average volume bid into the spot market, at different price bands, across all coal units in Queensland. Basically, the prices at which the generators are willing to dispatch capacity from their power stations.
While we can see a reasonable increase in capacity through December, the most obvious difference is the change in price bands seen from the first of January.
Starting in 2023, we can see that significant volumes are being offered into the spot market at lower prices.
Volumes of generation capacity which in October would have been dispatched at prices in the $100-$300/MWh range (and above) would now at the start of February be dispatched at prices in the $50-$70MWh price range. As Lasanthi said earlier, this price range roughly corresponds to a short-run marginal cost utilizing the coal intervention price cap of $125/t.
The majority of this volume is attributable to the Gladstone Power station – as was outlined in the original Federal Government announcement.
Moving into New South Wales, the most obvious change is the substantial increase in generation capacity bid into the market in early 2023, compared with October-November 2022.
Price band changes coming into 2023 are a little more subtle, compared with what we saw in Queensland. While some new volume was offered at lower price levels, the majority was initially bid at high levels, around the Market Price Cap.
However, in recent weeks we have seen volume move out of these high price bands and into the $70-$200/MWh range. This does represent a significant change compared to both early October, where there was less available capacity, and the start of 2023, where the additional capacity was bid in at high-priced levels.
To summarize, while at various times subdued demand and/or higher availability have contributed to lower average prices, changes to the prices that generators offer their capacity into the market have also played their part.
Spot prices over the last few months were characterised by significantly reduced demand from the QCLNG plant in Gladstone, due to 2 months of planned and unplanned maintenance. There was also a one-month outage at the Iona gas storage facility for most of November, which contributed to price volatility. Iona often assists to balance spot gas demand in the market, which normally reduces volatility, as well as providing deeper, seasonal gas storage.
In early December, there was an unplanned QCLNG shutdown, with prices falling to below $12/GJ into late January.
These maintenance activities coincided with a mild start to summer, and historically low residential and power generation gas demand, which meant that the market was relatively over supplied. Some of this surplus gas flowed south, injecting to the Iona underground storage facility in preparation for winter.
At the end of the last gas market update, Iona had reached critically low inventory due to heavy storage withdrawals required to balance the southern market over winter last year. Inventory at the start of October was just over 12 PJ. At the start of February, storage inventory had reached over 22PJ, representing injections of about 10PJ over the past four months, despite a one-month outage at Iona when no gas was injected.
Iona is currently 4PJ fuller than it was this time last year, inventories recovering quickly after high usage across winter last year where 14.5PJof inventory was withdrawn in three months.
Now comparing the last seven years of Iona inventory across a full calendar year, Iona is the fullest it’s been for this time of year, at over 22PJ, or 90% capacity. At the current rate of storage injections of about 100TJ/d, Iona is forecast to be full by mid-March, well ahead of the winter withdrawal season, and well ahead of previous years.
With the ACCC’s forecast market shortfall over the balance of this year, Iona will be critical to keeping the market supplied, high injections over the last few months have provided an early inventory buffer, supported by mild residential load and power demand.
Calendar year 2023 domestic forward prices commenced the quarter at around $30 per GJ, having rallied throughout most of 2022.
The federal government’s $12 price cap announcement on 9th December coincided with a sharp fall in calendar year prices, which almost halved overnight to $15/GJ. The price cap order commenced a few weeks later on 23rd December.
In January, the ACCC provided guidance on the price cap order, and the price differential between Northern and Southern markets widened. This location spread represents the market pricing in transport to move marginal gas from QLD to the southern markets, despite reduced trading liquidity.
Domestic gas for balance of year is trading between the $12 price cap and the current ACCC LNG netback price of around $25. Market liquidity has significantly decreased over 2023, 2024 and beyond, due to continued uncertainty over the impacts of announced and proposed legislation.
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