A Record Quarter: Five observations from AEMO’s Quarterly Energy Dynamics (Quarter 1, 2022)
Background
The Australian Energy Market Operator (AEMO) publishes its Quarterly Energy Dynamics report to provide the market with information regarding trends, outcomes and developments in the National Electricity Market (NEM) covering the Eastern seaboard, the Wholesale Electricity Market (WEM) covering Western Australia, and gas markets across the east and west coasts over the prior quarter.
Quarter 1, 2022 was characterised by severe weather events, a surge in plant outages and increased volatility in fossil fuel prices. These issues combined to make this a quarter of new records in the NEM which included record Queensland maximum operational demand and average daily Queensland spot prices. It also saw the lowest level of Queensland thermal generation availability for Quarter 1 in two decades and one of the highest differences in northern/southern state spot prices in recent years. Wholesale Demand Response capacity was dispatched for the first time in the NEM and renewable capacity and output reached new highs.
Our five observations from AEMO’s QED for Quarter 1, 2022 discuss the above points and some of the other key issues that are likely to be important to current and potential electricity market participants.
Our Insights
Queensland Records and the North-South Electricity Price Divide
Queensland recorded its highest average Q1 underlying demand (7,341 MW) in recent years. It also recorded an all-time high maximum operational demand of 10,058 MW on 8 March. High temperatures early in the quarter contributed to the 10 highest daily average spot prices recorded in Queensland during this quarter since the start of the NEM in 1998.
Q1 2022 saw the price divide between the northern and southern states that emerged in 2021 escalate further. Key observations include:
Queensland’s average spot price for the quarter ($150/MWh) was the highest of any NEM state while NSW average prices for the quarter were approximately $12/MWh greater than SA and Tasmania;
Queensland price increases were generally attributed to a decline in the availability of thermal generators during the quarter, which had the lowest Q1 availability since 2002;
Sharp increases in thermal coal and gas prices during the quarter (commodity spot prices generally doubled from 2021 to quarter 1 2022) arguably offered thermal generators opportunities to offer more volumes in higher price bands
Transmission constraints on the Victoria-NSW Interconnector held back south-north electricity flows, particularly during daylight hours.
These observations underpin the heavy reliance (>70%) in Queensland and NSW on ageing coal-fired generation. Unplanned outages in these large blocks of energy supply are often unable to be immediately and fully replaced by other dispatchable capacity, which is relatively smaller in scale at the current time.
Market participants across the NEM, and particularly in states with heavy thermal generation exposure, are likely to continue to experience significant price volatility and a likely continued increase in the north-south price gap as the market transitions towards clean energy. Increases and/or acceleration in the north-south interconnector investment (including VNI West, EnergyConnect and HumeLink) will contribute to reducing congestion-related price differences between the states.
Renewables and New Technologies increase their share of generation
AEMO reports that both renewable capacity and output continued to grow into Q1 2022, reaching 33.7% of capacity within the NEM (including hydro), with average NEM wind and solar output reaching a record quarterly high of 4,190 MW. As expected, continued increases to renewable output have led to a lower NEM carbon footprint, with record low carbon emissions for Q1 of any year (a reduction of 4% from Q1 2021).
As discussed above, this increase to renewable capacity did not lead to lower overall wholesale electricity prices in this quarter, and this is unlikely to change in the short to medium term as existing thermal plant retires across regions tightening 24/7 (‘baseload’) supply without sufficient renewable resource being available in each of those periods to reduce prices.
Electricity futures (FY/Calendar year) indicate market sentiment that high electricity prices will persist through 2023, with a steady decline thereafter.
Large energy consumers and retailers are likely to continue to look to financial contracts to manage risks associated with higher energy costs, with the impact of interest rates rises on the generation pipeline and subsequent demand for firm energy prices yet to be seen. Operators and new investors in renewable projects can continue to expect a varying mix of locational, weather, policy and market dynamics to influence the ongoing economics of their projects.
Battery Participation in FCAS Markets
AEMO notes that grid-scale batteries were the largest providers by fuel/technology type of Frequency Control Ancillary Services (FCAS) in Q1, reaching a combined share of 31% across the NEM’s eight FCAS markets.
This trend continued from last year, with an additional 125 MW of new batteries providing FCAS in Q4, 2021 compared to Q3, 2021 and an extra 200MW of batteries providing FCAS in Q1, 2022 vs Q1, 2021. Coal-fired generation’s average share of the FCAS market continued to decline this quarter with black and brown coal combining to provide 28% of FCAS enablement. Between Q1, 2021 and Q1, 2022, the increase in battery enablement for FCAS is almost identical to the decrease in black coal enablement.
Batteries can generally vary their active power promptly, making them well-suited to the provision of FCAS (which must respond quickly to sudden fluctuations in frequency across the grid). While many battery and new dispatchable technology projects rely heavily on FCAS revenues, in the near-term, this market is relatively shallow. As coal-fired capacity is withdrawn from the NEM over the coming years, storage is expected to dominate the FCAS markets. The risk here, if AEMO projections for the investment in storage technologies eventuate, is that batteries may swamp the market for FCAS. Current and future energy market participants may be able to offset this risk by participating in possible future opportunities in fast frequency response and virtual inertia markets.
Wholesale Demand Response Dispatch in Victoria and RERT in Queensland
The Wholesale Demand Response (WDR) mechanism commenced across the NEM in October 2021. This mechanism allows demand response providers to compete directly with generators in the spot market, and to be compensated for curtailment of demand. WDR capacity was dispatched for the first time in the NEM during this quarter, on 31 January, in response to high evening peak demand in Victoria. While small in volume (10MW), this response may have played some part in drastically reversing the surge in the Victorian spot price (over $10,000/MWh) to well under $100/MWh within one hour of WDR activation.
Q1 saw AEMO activate the Reliability and Emergency Reserve Trader intervention of up to 331 MW and additional voluntary load reduction on 1 February due to a combination of heatwave conditions and lower thermal plant availability during peak demand times (particularly outages of two units at Callide power station and the entire Kogan Creek power station).
As the market transitions away from coal-fired generation, there will be a continued reliance on a combination of new dispatchable technology (supply side), demand response (demand side) and interventions (market operator / regulator side) to support the secure, reliable and affordable running of the electricity market..
Wholesale Electricity Market Performance (Western Australia)
In the WEM, volumes offered at or near the price cap and floor had reduced as compared to Q1 2021. Some of this capacity appears to have been shifted upward from the price floor, or downward from the price caps, in the morning, evening and overnight periods.
There are several likely contributing factors for the lower volume offered near the price floor, such as the retirement of the cogeneration facility at the BP Refinery in Kwinana (80 MW), bidding adjustments following price floor events in 2019 and 2020, and/or bidding adjustments due to amendment of bilateral contracts – which may have previously required the generator to bid its full volume at the price floor.
The migration of offer volumes down from the price cap reflects that Perth experienced its hottest summer on record, with several days of very high electricity demand requiring peaking generation to run more frequently, and the faster afternoon ramping requirement caused by the growth of rooftop PV generation. The operators of these facilities often bid their capacity at or near the price cap until they forecast an opportunity to run their facilities, at which time they shift their bids downward.
As Australia transitions to the winter months, and average demand falls across the NEM, the continued reliability and bidding behaviour of existing thermal generation will continue to attract scrutiny. Beyond the next quarter, how reliability and spot prices will fare next summer (Q1, 2023) is also weighing heavily on the minds of energy traders, large consumers and retailers. The growing role of batteries in FCAS markets and the increasing share of generation coming from renewables will also continue to remain of interest, as the market seeks to validate its trajectory towards net zero emissions.
Link to AEMO’s Quarterly Energy Dynamics Report for Quarter 1, 2022: https://aemo.com.au/energy-systems/major-publications/quarterly-energy-dynamics-qed
For more information, contact Yatra Forudi at yforudi@renniepartners.com.au or Greg Ruthven at gruthven@renniepartners.com.au
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