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The Australian Energy Market Operator (AEMO), released its Summer 2021-2022 Readiness Plan. The plan provides a detailed short-term outlook with respect to energy grid security and market volatility. Traditionally, the summer/Q1 period is the most expensive to recontract C&I electricity, however, last summer was a significant outlier when compared to historical averages. Trans Tasman Energy Group has observed energy market future pricing almost return to historical form, leading up to the end of the year.

Echoing the Australian Bureau of Meterology’s summer forecast of a back-to-back La Niña summer season, AEMO predicts that the nation’s electricity supply will be sufficient for the hottest period of the year. Although a La Niña season will substantially effect potential Solar PV generation, this reduction of supply is forecast to be more than countered by the fact that Australia’s peak energy demand days will be lower in number and total energy required, as a result of the milder temperatures.

AEMO’s Chief Operations Officer, Matthew Gatt explains;

“Similar to last summer, we’re expecting less intense heatwave and bushfire conditions. However, these risks remain, along with likely tropical cyclones and flooding due to anticipated La Niña weather patterns.”

While reliability of supply in the short run is anticipated to be firm, market volatility is still very high due to the outages of Callide C Power Station (QLD), Hunter Gas Turbine (NSW), Mintaro Power Station (SA). In Victoria, the Yallourn W Power Station has been plagued by floods in its mine pit, as well as fire in a recent coal bunker, generation has not been at capacity for some time as a result. TTEG has advised its engaged clientele that it will monitor movements closely, and head to market as soon as more favourable market conditions present themselves.




AEMO also released its 2022 draft Integrated Systems Plan (ISP). The plan is AEMO’s roadmap for how Australia needs to develop its grid in order to deliver efficient power to Australians over the next three decades.

A brief summary of the plan can be accessed below.

Key points from the plan:

  • Thermal (coal) generators are exiting the NEM at least 5 years earlier than previously anticipated, which has placed huge pressure on the need to increase infrastructure spending on transmission/distribution networks. The ISP predicts that around two thirds of thermal units are to be decommissioned by 2030, and nearly the entire fleet of coal generators are to be offline by 2040.

  • AEMO predicts that the energy demand of the nation’s economy is to more than double by 2050 due to the increasing electrification of transport, building, industrial, and cooking heat needs.

  • AEMO modelling suggests a 9 fold increase of utility scale wind and solar generation is required to service the forecast future demand (15GW to 140GW). Rooftop solar and hydro power generation is also expected to increase 4 and 3 times their current volume respectively.

  • Whilst the talk of a rapid and unstoppable renewable energy transformation does bring about excitement amongst energy circles, well founded concern exists regarding the increasing of costs in end-user network charges. TTEG will be monitoring this space closely in order to keep its customer base informed of any market charge increases.

Click below for more information.





Domestic Gas Price Volatility

Wholesale gas prices in the eastern states have more than doubled since the winter of 2020.  Following the explosion at Queensland’s coal-fired Callide power station in late May this year, increasing amounts of gas-fired generation have been required to fill the gap—particularly as solar generation wanes during the evening peak periods.  Domestic gas storages were rapidly depleted in early winter to meet demand and international oil & LNG prices continue to rise.  Scheduled maintenance at the Longford gas field in Victoria also significantly limited available gas supply and contributed to higher prices.


As winter in the northern hemisphere rapidly approaches, Asian demand for Australian LNG is continuing to increase.  Domestic gas retailers and other market participants are endeavouring to replenish depleted gas storage levels in time for the next Australian winter.  With domestic gas supply remaining tight and LNG netback prices continuing to rise for the foreseeable future, many experts in the market forecast domestic gas futures prices to increase over the course of 2022.  In other words, the quoted natural gas rates for retail contracts with supply start dates in 2023-25 are expected to rise over 2022.


Long-term Domestic Gas Supply Outlook

The long-term gas supply outlook for the east coast (2023–2032) remains uncertain.  The southern states face a potential 30 Petajoule supply shortfall as early as 2024 and southern gas production is expected to lag demand by 113 Petajoules the same year.  Unless an LNG import terminal or more speculative domestic sources of supply are developed to meet production forecasts, this will likely become a reality.  Whilst the proposed LNG import terminal at Port Kembla, NSW expects first flow of gas to occur in early 2023, the project is yet to take a final investment decision.


WA natural gas retail prices are on the rise as well, mainly driven by the cost of upstream gas going up. Upstream providers only have to supply a small % of gas to the domestic market so the rest is being reserved to get a higher cost from local retailers or ship offshore as LNG. While commodity prices were between $4-5/GJ only 12 months ago, we are now up to $7-9/GJ depending on the contracting years. Gas will continue to rise as supply tightens up pushing commodity prices up


[1] An LNG netback price is a measure of an export parity price that a gas supplier can expect to receive for exporting its gas. LNG netback prices based on Asian LNG spot prices currently play an important role in influencing gas prices in the east coast gas market.


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