Wholesale Energy Market Update: September 2024

POWER MARKET UPDATE 

We’re kicking off today with a look back at the recent history of average monthly spot prices.

Monthly average spot prices

Here we’ve divided the spot price averages into two components: the under-cap outcomes, which is an average of spot prices capped at $300/MWh, and the over-cap, the value of all spot prices above $300/MWh. You can think of the over-cap value as a measure of how often the price spikes towards the market price cap or how “volatile” prices are.

In our last update, we had moved through a period of relatively lower price outcomes in Q4 ‘23 and Q1 ‘24, when compared with recent years. Since then, spot prices across the NEM have surged to very high values, trumped only by the record-breaking prices of 2022.

This has continued a recent pattern of higher, and more volatile, spot price outcomes occurring across the winter quarters, rather than the traditional, high-demand period of Q1 and summer.

We can point to specific events driving this trend: the Callide C explosion in May 2021, extreme fuel costs and low availability at the height of the energy crisis in 2022 and the Liddell closure in April 2023. But what has driven the high outcomes of this winter?

While we have seen decent demand levels, including a few monthly records, the real story behind the high prices has been the supply side.

Wind and hydro and NEM-wide generation

Here we are looking at the overall capacity factors of wind and hydro generators across the NEM. The capacity factor of a power station shows how much energy it actually produces compared to its maximum possible output. The line shows where those capacity factors have averaged over the months in 2024, while the shaded area highlights the range of monthly capacity factors over the previous six years.

Clearly, weather impacts have driven down both wind and hydro capacity factors to quite low levels through Q2. Low wind conditions have impacted wind farms across the NEM, while dry conditions and low winter rainfall have seen hydro plants forced to conserve water.

In terms of share of generation across the NEM, we can see from this table that hydro was well down in Q2 compared with previous years. Similarly, despite continuing increases in capacity, wind’s share was down year-on-year, the first down tick in some years.

Price setters

The impact on price is well illustrated by this figure from the recent AEMO Quarterly Energy Dynamics, which shows the breakdown by fuel-type of price setting generating units, comparing Q2 ‘24 to Q2 ‘23. Higher cost dispatch gas and batteries are setting prices more, while cheaper wind, brown coal and hydro much less.

Coal’s share of the generation mix was up year-on-year this Q2, though with the retirement of Liddell Power Station and ongoing outages at the Callide C Power Stations, coal’s share of NEM generation has been concentrated across fewer generating units.

In summary, high spot prices during Q2 were primarily driven by lower wind and hydro output being replaced by higher cost generation.

Now let’s take a look at how the changing spot price dynamics is impacting the contract market.

Power forward prices

Forward flat swap prices represent the overall view of market participants on what the fair value of electricity will be in a given period. As Andrew mentioned, caps are an indicator of expected volatility while the energy price is the expected value of electricity outside of cap periods. The flat swap price is the sum of these two prices and therefore can move due to a change in expected energy or volatility or both.

Forward swap prices

In our last update, we discussed how both forward swap and cap prices had trended down but had remained at historically elevated prices. Much of the decrease in swaps was due to a reduction in expected energy prices, while cap declines were fairly subdued as elevated volatility expectations remained priced in.

However, as we went into Q2, the events in the spot market discussed by Andrew led to market participants drastically increasing their energy price outlook, while caps had modest increases despite significant volatile pricing events. As such, the big movements up in the swaps in early to mid Q2 were largely driven by energy.

Forward swap prices NSW

Another interesting change we saw in Q2 was the return of backwardation in NSW forward contracts. Backwardation is when near-term contracts attract a higher price than later-dated contracts. Uncertainty over the future of major NSW coal generator, Eraring, led contracts in the “post-Eraring” years, i.e. Cal26 and Cal27, to attract a major premium.

This occurred for a couple reasons: the overall market belief that the reduction in NSW capacity post-Eraring would lead to high prices, and the natural supply of NSW contracts, and therefore contract liquidity, would be much lower.

The Eraring extension announcement in May signalled a reversal in these factors. However, uncertainty around the specifics of the agreement remained, allowing backwardation to return – albeit modestly.

Forward cap prices

At the tail-end of Q2, swap prices started to decline. This was largely driven by energy pricing, as the conditions contributing to high energy prices in the spot market began to ease. The downward momentum in swap prices was arrested as we entered Q3, with more volatility in spot prices finally leading to a greater proportion of value moving into the cap products.

GAS MARKET UPDATE

The main theme this winter has been the intermittency of renewable generation, which has not only reminded us of the challenges of the energy transition, but also highlighted the complementary nature of gas and renewables.

Spot gas prices

Cold, cloudy and still conditions prevailed over the southern demand centres this winter, driving chilly mornings and evenings. This underpinned multiple periods of volatility and high pricing, exacerbated by concurrently high residential heating and gas generation demand when wind was low.

The average spot price from April to date was $13.30/GJ, with periods of sustained above average pricing in late May and early June. Prices reached $28/GJ on 20th June, with AEMO issuing a threat to system security notice.

Demand highlights

LNG demand was at annual lows, due to a combination of planned maintenance and fewer LNG cargo exports in winter than summer. This provided additional QLD gas for the southern market when it was needed most.

Residential heating demand was high, driven by one of the coldest winters in the past seven years.

Finally, gas generation demand was high and volatile, driven by exceptionally low wind output combined with a small number of unplanned coal outages.

GPG demand

This winter, periods of higher gas demand generally correlated to higher and more volatile price periods, observed in late May and early June.

The converse was also true, with high wind output mid-July reducing gas generation.

From July onwards, despite continued periods of low wind generation, increased gas supply put downward pressure on gas prices.

We’ve already mentioned LNG plant maintenance and cargo scheduling in QLD resulting in high southern gas flows across winter close to capacity, ramping up in June following the completion of APA’s Stage 2 East Coast Grid Expansion works.

Supply highlights

Key southern production facilities Longford and Otway operated at close to 100% capacity, particularly until late June, when Longford returned from unplanned maintenance, and the Otway Enterprise gas field started production.

Storage

The Iona underground gas storage facility entered winter at close to full. However, gas was withdrawn at record rates, storage inventory falling to 10PJ or 40% of nameplate capacity in early August.

As we entered the final couple of weeks of winter spot prices softened, with some participants opportunistically refilling storage, driven by warmer than usual weather in Melbourne combined with increased wind generation.

This year, Iona was critical to keeping the southern market supplied, with withdrawal rates very close to the records of 2022 – starkly different from last year’s withdrawal profile. Iona is now expected to refill through spring and summer in preparation for next winter.

Forward prices

The forward curve for domestic gas is in mild contango – driven by expectations of continued supply decline later this decade – despite next year expected to be sufficiently supplied, as forecast by recent ACCC and AEMO publications.

On the other hand LNG netback prices have risen, driven by robust Northern Hemisphere summer cooling demand, continued geopolitical tension and easing European gas storage inventories – the forward curve in steep backwardation from 2026 to 2027.

Domestic market forward liquidity has improved after final exemptions were granted by the ACCC from the Gas Market Code in June, supported by the launch of the new ASX Wallumbilla Gas Futures product in August. The new Gas Futures product delivers increased market transparency, a longer dated price signal across a rolling three-year period and additional forward hedging liquidity for producers, consumers and intermediaries.