Australian LNG under pressure
A global supply glut, cheaper rivals and tightening emissions policies
are a growing problem for Australia’s costly gas-export plants
At least two of Australia's new liquefied natural gas-export facilities in Queensland may run under capacity until global demand exceeds supply around 2022. Even then, the need for their product might be less than thought.
Changing buyer needs, an unanticipated shortage of onshore coal-bed methane (CBM) to supply the trains, and possible federal intervention to restrict exports in preference for eastern Australia's tightening domestic market could see plants run under nameplate capacity for some years. Longer term, cheaper LNG and the adoption of clean technologies could strand the high-priced Queensland assets altogether.
Matt Howell, senior research analyst for consultancy Wood Mackenzie's upstream Australia unit says all three of Queensland's LNG-export plants will be run at less than full capacity over the next five years.
"The amount will vary both by project and through time, but we expect production to be around 1m-1.5m tonnes a year below capacity per facility. In QCLNG's case, that's a reflection of Shell's global LNG portfolio. For the other two projects, there is uncertainty about whether the buyers need all of the full contracted volumes."
Gas supply will also be a problem, he reckons, especially for Gladstone LNG. Developer Santos has already said output will now rise to just 6m t/y in 2019. "We don't expect it to rise significantly above that in the few years after that either," Howell added.
1m-1.5m t/y - Amount of capacity that could be unused at each Queensland LNG project
Sanctioned at a time when oil prices were over $100 per barrel, all three of Queensland's LNG facilities have significantly dropped in value now that spot prices are barely holding half that price. Total write-downs amount to A$10bn ($7.4bn) after tax, including A$4.8bn at Shell's QCLNG, A$4.6bn at Santos's GLNG, and A$1bn at Origin's APLNG project.
The Queensland facilities are particularly vulnerable since they rely on costly drilling of onshore CBM wells to maintain production.
Santos has found much less CBM than it expected when it sanctioned GLNG. Tumbling oil prices have also cut exploration investment, leading Santos to buy at least half of the project's gas from third parties. In turn, this has left less gas available for the east coast domestic market-bringing pressure from the federal government to limit exports.
Not everyone agrees that Queensland's LNG facilities will be first to shut in export capacity. Dale Koenders, Citi's local head of energy and utilities research, told Petroleum Economist that contractual offtake prices for Australian projects would remain attractive enough to continue developing CBM assets.
"In the US, the marginal cost of supply is effectively Henry Hub x 115% plus shipping costs to land in your market," he says. "Even if Henry Hub is at $2.50-3 per million British thermal units x 115%, plus shipping cost, you're probably at a similar or higher marginal cost to CBM. That's why I think the US is more likely to curtail and so if there's any curtailment in Queensland CBM it'll only be down to contractual levels," Koenders adds.
Simon Currie, a Sydney-based Partner at law firm Norton Rose Fulbright, is also optimistic for the local sector. Plant underutilisation has tended to be the outcome of major input or facility problems, as in Angola, he notes, "or a fundamental shortage of feedstock like we saw in Egypt, and then in other cases obsolescence or the wrong market structure. I really don't think you can apply those same principles to Australia," Currie says.
Still, longer-term resilience will need a change of mindset, he believes. For the Queensland products, he says, the question is: "are the supply chains sufficiently robust to continue to deliver everything those plants need over a 20-year horizon? It's not like Qatar's North Field. You have a constant business getting the CBM out of the ground. It's not a straw into a big field. You just can't predict what you will get out of each well and the costs associated with that, the water purification costs, that whole thing has been overestimated."
Australia's rising capacity will make it the world's biggest LNG exporter—but only between 2018 and 2021, according to forecasts. After that, surging capacity from the US will give it the lead until 2035, during which time the US will account for 29% of total exports. Australia and today's leader Qatar will lag with 16% and 12%, respectively.
That outlook doesn't account for Qatar's recent decision to lift its moratorium on fresh development of the North Field-a move that could add to its capacity, posing another threat to higher-cost Australian suppliers.
Globally, LNG suppliers will also have to thrive despite climate-change policies to reduce emissions and new battery technologies that could make cheap renewable energy a viable baseload power source for utilities that now rely on gas.
A report last year from Carbon Tracker, which assesses risks to the hydrocarbons sector from emissions policy, said that more than $280bn worth of LNG projects-including $68bn in Australia-would be redundant if global rules on emissions tightened sufficiently.
Exporters are pinning hopes on southeast Asia to account for about 70% of future gas-demand growth. Yet fuel switching to technologies offering distributed power-generation options at greater flexibility and potentially lower cost, could eat into this market.