After more than a year of delays, the first shipment of liquified natural gas will leave Woodside’s $15.4-million Pluto project in Western Australia this month.
But the start of exports is not just a big achievement for Australia’s biggest oil and gas company by market value. It is also a milestone for the country’s gas industry, which is poised to experience a period of rapid growth that could see Australia surpass Qatar as the world’s largest LNG exporter by the end of the decade, analysts say. It will also add a third leg to the country’s resources boom, which until now has been all about coal and iron ore exports.
However, the industry faces a number of challenges, according to sector watchers. Projects costs are rising, regulation is strict and Australia is facing competition from other countries – notably Canada and the U.S., the latter of which could become a leading exporter due to its shale gas boom. Then there is speculation of possible changes to the tax system.
It is against this backdrop that some of the world’s largest oil companies, such as Chevron , Royal Dutch Shell and BG Group, will have to decide whether to invest billions in extending or starting new projects.
There are currently two LNG projects operating in Australia: the North West Shelf and Darwin LNG, which have a combined capacity of about 20 million tonnes a year. By 2018, that figure should reach 80 million tonnes a year, according to Australia’s Bureau of Resources and Energy Economics (Bree) as eight huge projects, including Pluto and BG’s $20.6-billion Queensland Curtis venture, come on stream.
Citigroup analyst Mark Greenwood says: “The addition of 60 million tonnes in seven years will represent faster growth than achieved by Qatar.” He predicts Australia will go on to become the world’s biggest LNG exporter in the absence of any further expansion in Qatar.
In total, about 70 per cent of the world’s LNG capacity currently under construction is located in Australia, according to Bree, which cites extensive gas reserves capable of supporting 40 to 50 years of production, low sovereign risk, an established reputation as a reliable supplier and geographic location as reasons behind the LNG investment boom.
About $200-billion has been committed to the eight approved LNG projects and another $150-billion of investment in plant extensions and new projects – the equivalent of 60 million further tonnes of production per annum – are awaiting final investment decisions.
But given continued cost inflation, potential changes to the tax system – the petroleum resource rent tax has been extended to include onshore gas fields – and increased competition, it is not clear that big “green-field” projects, such as Woodside’s $39-billion Browse project or Shell’s $20-billion Arrow venture with Petrochina, will go ahead as first envisaged.
Indeed, Woodside said on Monday it would delay making a final investment decision on the Browse LNG project in Western Australia until the middle of next year after the government approved changes to its leases.
John Hirjee, senior energy and utilities analyst at Deutsche Bank in Melbourne, says: “Australia is probably the most expensive [place]to build a big LNG project, and if costs are still going up then the likelihood that some green-field projects get delayed or don’t make it over the line is quite real.”
Bree estimates Chevron’s Gorgon and Wheatstone projects have a capital cost of $3.1-billion per million tonnes of annual capacity. In comparison, the PNG project in Papua New Guinea has a capital cost of $2.3-billion and the soon-to-be completed Angola LNG project $1.7-billion.
And then there is the issue of tax. David Byers, chief executive of the Australian Petroleum Production and Exploration Association says: “Australia is developing a damaging propensity for continually fiddling with the fiscal regime on which long-term investment decisions are founded.”
The ruling Labor government is reportedly considering several changes to the current system, including adjusting the way resources companies can deduct exploration costs and the rules on depreciating capital expenses.
It is also unclear whether the likes of Chevron, Shell and Woodside will be able to continue selling gas into Asia at high prices for decades to come as competition intensifies. The U.S. recently approved its first LNG project, the Sabine Pass plant in Louisiana, and there have been discoveries in Tanzania and Mozambique, which analysts believe will eventually find their way to Asia.
It remains to be seen whether the U.S. becomes a significant LNG exporter given concerns over energy security and lobbying by large industrial companies that are enjoying a cost advantage from low-priced domestic gas.
However, that will not stop buyers in Japan, South Korea and Taiwan using it as leverage to drive down the prices, says Craig McMahon, head of Australasia upstream research at Wood Mackenzie.
“The major LNG buyers will want to see the likes of Mozambique and Tanzania succeed. More supply promotes more competition and helps exert a downward pressure on pricing,” he adds.
But ultimately, Asian buyers will still look to Australia to provide the bulk of their LNG needs because of its low political risk and reputation as a reliable exporter of commodities.
“From a buyer’s perspective security of supply is critical and foremost in their minds when they are contracting volumes,” says Mr. McMahon. “While Australia may have challenges, it’s still OECD production, it’s still low political risk and even if projects are a bit late, it is still safe and secure production for the next 20 to 30 years.
“The whole U.S. LNG proposition is based on cheap Henry hub gas [the benchmark U.S. gas price]and that’s something a Japanese or South Korean buyer can’t control and that makes them feel uncomfortable.”
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