EnergyQuest’s latest East Coast Gas Outlook to 2040, Balanced on the Edge, reveals a widening long-term divide between gas supply and prices in Queensland/NT and the southern states – with the industry balanced on the edge of not meeting demand in just a few years.
The new report is the leading energy consultancy’s first in-depth analysis of the long-term outlook for the east coast gas market since December 2019.
EnergyQuest CEO, Dr Graeme Bethune, said that based on LNG netbacks, the company’s latest base-case gas price projection is for a 2030 gas price at the Wallumbilla hub in Queensland of $8.70/gigajoule (GJ) (real 2021 $), similar to current spot prices ($8.90/GJ on 5 August). By contrast, the Melbourne price is projected to be $11.05/GJ in 2030, significantly higher than the current spot prices ($8.05/GJ on 5 August) and well beyond the capacity to pay for energy-intensive Victorian manufacturing. The Wallumbilla Hub is closest to the large CSG fields and Northern Territory gas.
“The Northern Region, which includes Queensland and the NT, is projected to be self-sufficient in gas supply – even with the three LNG export projects at Gladstone – until around 2030 when the CSG fields begin to decline and limit LNG feedstock gas.
“The Southern Region, comprising NSW, Victoria, Tasmania and South Australia, is already contending with the decline of the legacy basins. By 2030 we project Victorian gas production (which also supplies NSW, South Australia and Tasmania) to be 68% lower than in 2020. The southern states will need support from Queensland and the Northern Territory plus at least two LNG import terminals. The southern supply outlook also relies critically on significant gas production from the NSW Narrabri gas project by 2025. The project is yet to be sanctioned.
“EnergyQuest’s analysis is based on conservative assumptions about future gas demand, assuming Victorian demand in 2030 is 12% lower than in 2020. In contrast, the recent report from Infrastructure Victoria on options to reduce Victorian gas demand to achieve zero emissions by 2050, actually assumes higher gas demand than does EnergyQuest’s analysis. In all scenarios presented by Infrastructure Victoria, gas consumption in 2030 is higher than the EnergyQuest business-as-usual case and also higher than actual consumption in 2020, so the shortfall could be even larger than the 125 PJ we are projecting in 2030.
“Moreover, Victorian peak demand days can swing 40% around winter averages, and the winter seasonal average is three times the summer demand. The seasonal and peak day supply to the southern states depends critically on Longford and the declining Gippsland Basin, limited gas storage and the swing capacity of northern gas being shipped long distances.
“To address the forecast shortfalls in production, there are five proposals to build LNG import terminals on the east coast of Australia, at least one of which is targeting first gas to meet winter 2023 peak demand. We believe that at least two of these are needed.”
Dr Bethune said APA Group’s planned 25% expansion of the pipeline capacity from the Wallumbilla Hub in Queensland to Sydney should also help alleviate forecast southern winter peak demand in 2023.
“However, 91% of the expanded pipeline capacity from Wallumbilla to Moomba for winter 2023 is already contracted which will limit firm access on the critical peak days. Also sending gas by pipeline from Queensland to Melbourne is expensive, increasing Victorian gas prices.
“Good progress has been made by companies in maintaining or lowering gas production costs. However, it is the continued decline in gas reserves which is a major concern. Following write-downs of Queensland gas reserves, we are now seeing write-downs in the southern states. Gas reserves in the Gippsland Basin, the major basin offshore Victoria, decreased by 556 PJ in 2020, 301 PJ more than production, equivalent to losing nearly a year’s gas demand in Victoria and NSW.”
The EnergyQuest report states that LNG imports and alternative markets for Gladstone LNG are expected to set gas marginal pricing by 2025, which will see a switch in domestic gas prices from cost of supply to LNG-linked global prices.
“Gas buyers and sellers are facing an increased degree of price uncertainty and risk. International energy prices are increasingly setting east coast domestic prices, increasing the volatility in domestic gas prices. Already in 2021, the ACCC LNG netback price series has swung between A$6.44/GJ and A$19.62/GJ. Managing this volatility is a major challenge whether you are a gas buyer or seller”, he said.
Dr Bethune said the east coast gas market faced tightening supply and higher prices over the long term, despite the shift to sources of lower-emission energy such as wind, solar and hydrogen.
“We modelled a number of low-carbon scenarios because there is a great deal of uncertainty about future demand for gas in a net zero or low carbon world. But the underlying supply shortage does not go away.
“For example, AEMO’s green hydrogen scenario does decrease east coast gas demand, but by 2040 this would still be equivalent to only one of the proposed LNG import terminals, compared to our business-as-usual scenario. The greatest near-term potential for decarbonisation lies in blue hydrogen (hydrogen produced from natural gas with carbon capture and storage), rather than the much more expensive green hydrogen. Natural gas has a critical role to play in decarbonisation of the energy system.”
Further information about the East Coast Gas Outlook 2021 report is available from firstname.lastname@example.org