High temperatures push electricity demand increase, but prices fall as renewables continue to grow in the National Electricity Market

3 min

Renewable energy generation drove down wholesale prices in the first quarter of 2024 despite higher temperatures pushing up electricity demand.

The amount of renewable energy being fed into the grid grew to 39%, up from 37.4% in Q1 2023.

AEMO’s latest Quarterly Energy Dynamics report shows that despite heatwave conditions and extreme weather events causing high price volatility, wholesale spot prices on Australia’s east coast were down 8% on Q1 2023, to $76 per megawatt hour (MWh).

“The move to renewables over traditional coal-fired power generation is well and truly underway and is happening at record pace,” AEMO’s Executive General Manager of Reform Delivery Violette Mouchaileh said.

“We are increasingly seeing renewable energy records being set which is a good thing for Australian consumers as it is key in driving prices down and NEM emissions intensity to new record lows.”

There was still evidence of a north-south divide in pricing across the National Electricity Market (NEM).

“Continuing the trend observed in recent quarters, there is a notable wholesale price separation between the NEM’s northern and southern regions,” Ms Mouchaileh said.

Due to record demands and weather events, Queensland was the only NEM region where wholesale spot prices increased on Q1 2023, recording the highest regional quarterly average of $118/MWh, followed by New South Wales at $87/MWh.

Tasmanian wholesale spot prices averaged $67/MWh, South Australia $55/MWh, while Victoria recorded the lowest quarterly average price of $52/MWh.

Victoria’s average price was the lowest despite a severe storm event on 13 February 2024 causing the loss of transmission lines, generation outages and price volatility which contributed nearly $15/MWh to that quarterly average.

In the three months to 31 March 2024, operational demand across the NEM averaged 21,552 megawatts (MW), the highest Q1 average in four years.

The demand was most evident in Queensland, where a record maximum operational demand of 11,005 MW was recorded on 22 January 2024.

Driven by new and recently commissioned capacity in New South Wales and Queensland, grid-scale solar generation had the greatest increase in output setting a new record of 2,164 MW, an 18% lift in quarterly average output from the same time in 2023.

Distributed photovoltaics (PV) output hit record highs in Victoria (787 MW), South Australia (445 MW) and Tasmania (58 MW) and reached its highest level for any Q1 in Queensland (931 MW) and New South Wales (1,050 MW).

“Wind generation had the next largest increase, up 5% with output from grid-scale batteries up a massive 134% year-on-year,” Ms Mouchaileh said.

East Coast wholesale gas prices increased in all markets compared to Q4 2023 but were 3% lower than the same time last year, averaging $11.60 per gigajoule (GJ) for the quarter.

Over the first three months of 2024, gas demand increased by 10% compared to the first three months of 2023, driven by higher demand for Queensland LNG exports (+44 petajoules (PJ)).

Domestic gas supply shifts, which have been observed since Q2 2023, continued, with declining production from gas fields connected to the Longford Gas Plant in Victoria the main contributor.

Production at Longford fell by 10 PJ compared to Q1 2023, with available capacity at Longford dropping below 300 terajoules (TJ) per day for part of the quarter, the lowest planned capacity since 2004.

The quarter also saw AEMO trigger east coast gas system functions for the first time, issuing directions to mitigate supply risks, following a pipeline rupture on the Queensland Gas Pipeline (QGP) on 5 March.

In Western Australia’s Wholesale Electricity Market, multiple heatwaves saw the quarter experience seven of the 10 highest maximum average operational demands of all time. This included a record maximum average of 4,233 MW on Sunday 18 February when the daily maximum temperature hit 43°C.

Demand reduction, in the form of Demand Side Programmes (DSP) and Supplementary Reserve Capacity (SRC), were activated on 14 occasions in the quarter to 31 March, with gas, coal and wind generation assisting to ease demand.

In Western Australia’s gas market, supply disruptions and increased gas fired power generation, production for the domestic market was at 100.3 PJ, almost matching consumption at 97.2 PJ.


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