A year on from the suspension of the National Electricity Market (NEM), less volatility has resulted in wholesale electricity prices exceeding $300 per megawatt hour (MWh) in 3% of intervals in the June quarter, compared to 26% in Q2 2022.
AEMO’s Quarterly Energy Dynamics report shows from April to June, wholesale electricity prices in the NEM averaged $108 per megawatt hour (MWh), 59% lower than record high quarterly price set in Q2 2022 ($264/MWh), but 31% higher than the March quarter.
By region, quarterly average prices ranged from $64/MWh in Tasmania to $137/MWh in New South Wales, with Victoria, South Australia and Queensland averaging $89/MWh, $124/MWh and $126/MWh, respectively.
AEMO Executive General Manager Reform Delivery, Violette Mouchaileh, said less volatile market conditions, improved generation availability and higher renewable output put downward pressure on wholesale electricity prices.
“Increased market share of lower marginal-cost renewables helped push down the wholesale electricity cost from Q2 2022, despite this quarter having the highest Q2 underlying1 demand recorded since 2016,” Ms Mouchaileh said.
“In addition to increased wind and grid-scale solar output, lower thermal-coal costs and a net increase in black-coal generation availability in NSW – despite the retirement of the Liddell Power Station – helped reduce year-on-year wholesale prices.
“Rooftop solar generation increased 30% from Q2 2022, which reduced electricity demand from the grid. Coupled with higher renewable output, wholesale prices were zero or negative 9% of the quarter throughout the NEM, a new Q2 record,” she said.By market share, rooftop solar (1.8%), wind (1.6%) and grid-scale solar (1.4%) generation increased compared to Q2 2022, while gas (-3.2%), hydro (-1.2%) and black coal (-0.6%) decreased.
By state, wholesale prices at or below $0/MWh occurred the most in South Australia (17%), Victoria (13%) and Queensland (9%), rising to 29%, 20% and 25% respectively between 9am and 5pm.
NEM total emissions declined this quarter to the lowest Q2 levels on record at 28.7 million tonnes of carbon dioxide, 6.6% lower than Q2 2022, while emissions intensity dropped 4.3% to 0.61 tCO2 e/MWh.
During the June quarter, east coast wholesale gas prices averaged $14.20 per gigajoule (GJ), the second highest Q2 price after last year’s record of $28.39/GJ. Gas demand decreased by 5% this quarter compared to Q2 2022, driven by lower usage for gas-fired generation.
Meanwhile, a fundamental shift in domestic gas supply is underway, driven by declining production from gas fields connected to the Longford Gas Plant in Victoria. Aggregate Longford production decreased by nearly 25 PJ compared to Q2 2022, and daily production levels also decreased. Longford supply has mostly been replaced by a net increase in Queensland supply (11.3 PJ).
In Western Australia’s Wholesale Electricity Market (WEM), an all-time record high weighted average Balancing Price ($113/MWh) was set in Q2 2023, along with a new Q2 maximum operational demand record (3,652 MW).
“The WEM experienced price increases due to a reduction in energy availability, mostly coal-fired and wind generation, and high demand due to cold temperatures during the quarter,” Ms Mouchaileh said.
“Specifically in June, AEMO forecast multiple lack of reserve conditions due to forced outages of scheduled generators and low wind conditions, resulting in only two-thirds of the total installed generation capacity being available for dispatch,” she said.
A total of 100 PJ was consumed in the WA domestic gas market in Q2 2023, an increase compared to both 3.4 PJ in Q2 2022 and 7.6 PJ in Q1 2023. A key driver of this was increased gas consumption for electricity generation. Q2 2023 also saw an increase in total WA domestic gas production of 100 PJ.
1 Underlying demand is the total volume of electricity supplied from grid-scale generation and storage, and estimated rooftop solar output.
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