Imports are a cap on higher gas prices and the margins of gas delivered through the pipeline network. The piped diversions of CSG-LNG from Queensland are currently the marginal supplier in the east coast market. As the existing production declines, domestic prices will increase due to the higher development and transport costs of new supply.
Peak gas demand in eastern Australia (June through August) corresponds with the low season for LNG spot prices. The importer may therefore be able to take advantage of this seasonality to improve the LNG import economics. However, this would be unlikely to affect its relative price against gas diversions from the CSG-LNG projects as both are driven by the LNG spot price.
Importing gas also makes sense from a strategic perspective.
Companies that have existing pipeline capacity agreements are able to transport gas from Queensland to Victoria for less than the US$2.18/mcf that we have assumed. They would also have guaranteed pipeline access and so imports would be less attractive. But the movement of gas is more difficult and expensive for companies without these agreements, or without agreements spanning the whole route. For them, importing gas would avoid these costs, and access uncertainty.
Around 85% of Victoria's gas production comes from BHP/ExxonMobil through the Bass Strait JV and the small Minerva field (of which BHP has 90%). An LNG import terminal, which has an estimated annual cost of around US$60 million, would provide additional bargaining power to gas buyers. In AGL's case, this is only 7.5% of what it spent on gas in the 2016/2017 financial year. Even a potential import terminal could lead to gas purchase savings if the development is viewed as credible.
But the import terminal is an additional expense and adds risk to the gas buyer. It is a movement away from its core business and adds risk through additional exposure to the LNG spot price. There is an option to reduce some of this risk through contracting LNG, but that would reduce flexibility, fix costs to a degree and increase exposure to the LNG contract benchmark price.
As domestic legacy fields decline, diversions from the Queensland CSG-LNG projects are going to be the marginal supplier of gas. The projects are expected to continue to divert volumes into the market as domestic prices rise, and to avoid any political backlash due to shortages. But as we enter the next decade, our new Australia gas network modelling suggests that the amount of spare capacity available in the existing pipeline infrastructure connecting Queensland to the southern states will decrease, and available supply will likely fall below current demand estimates. So either additional sources of supply need to be found, new pipelines have to be constructed, or imports will be required.
If no new developments are sanctioned in south-eastern Australia, those markets will be relying on gas from Queensland and the declining Bass Strait. However, by 2028 there will be insufficient capacity in the existing pipeline network from Queensland to keep the region fully supplied. There is also considerable uncertainty around what volumes would be made available by the CSG-LNG projects, particularly as the projects begin to drill out their less productive acreage. If domestic prices are lower than the cost of development then no volumes will flow. The two supply solutions are the addition of extra pipeline capacity vs. an LNG import terminal, and it is likely that both will occur.
The above commentary is from Matt Howell, senior analyst, Australasia upstream, Wood Mackenzie.