Australia is no stranger to the idea of transnational or even international pipelines when it comes to solving the vexed issue of getting enough gas to its eastern seaboard, home to its biggest cities.
Australia currently has two separate gas pipeline networks in the west and east of the country which supply markets of around 1 Bcf/day and 1.6 Bcf/d respectively. A much smaller, also separate, network in central Australia services the Northern Territory capital of Darwin.
In the 1990s, Western Australia was pushing the idea of a pipeline to transport its massive undeveloped offshore gas reserves to consumers 4,000 km away on the more heavily populated east coast. At the time fields such as Scarborough, Torosa and Gorgon, discovered in the 1970s and 1980s, were seen as remote but potential sources of gas for the eastern domestic markets, which were then expected to run short before 2010.
Gorgon operator Chevron was still kicking around the idea of a west-east transnational pipeline to market some of the field’s 40 Tcf of gas in the early years of this century. That was in a period when gas supply to the east from central Australia’s Cooper Basin had peaked and before the emergence of the coalseam gas industry in the eastern states of Queensland and New South Wales.
Blog entry continues below…
|Request a free trial of: International Gas Report|
|International Gas Report is a biweekly report that intelligently analyzes what is happening in the natural gas industry, improving your vision and sharpening your competitive edge. Through its unrivalled network of global correspondents, it covers the whole gas chain, from the well-head to the burner tip, in Asia, Europe, the Middle East, Africa and the Americas, including gas transport, regulation and the ever-present problems posed by shifting geopolitical concerns.|
Today those three Western Australian fields are either in development or awaiting approval primarily as LNG export projects. Work on Gorgon got underway in 2009 and the project is set to start producing 15.6 million mt/year of LNG from early 2015.
Scarborough and Torosa are now expected to be developed using the emerging floating LNG production technology which involves mounting the liquefaction facilities on massive barges permanently moored at the offshore fields. Scarborough is the subject of a development proposal by ExxonMobil and BHP Billiton, and Torosa, along with the nearby Calliance and Brecknock fields which make up the Woodside Petroleum-operated Browse project, also looks set to be developed using FLNG.
Chevron was also behind a proposal, floated in the late 1990s, to pipe gas 4,000 km from Papua New Guinea’s Kutubu fields to domestic markets in Queensland. That plan foundered on a lack of committed customers and was finally laid to rest in early 2007, after which the attention of the PNG resource holders also turned to LNG.
By then the emergence of the coalseam gas industry in Queensland was in full swing. The CSG sector had been sparked into life by a Queensland government policy requiring that 13% of electricity sold in the state from 2005 onward be generated from gas.
The latest proposal for a transnational interconnection between Australia’s pipeline networks was initially aired in recent months by former Chief Minister of the Northern Territory Terry Mills, as part of his efforts to secure the future of Rio Tinto’s alumina refinery at Gove. In February, just before being ousted in a party room coup, Mills secured a deal under which Gove would be supplied with gas from Eni’s Blacktip offshore field, heralding a project which would include the construction of a A$500 million pipeline to the plant.
“The complex negotiations to get gas to Gove also highlighted a need for a national pipeline grid, connecting the Northern Territory with the existing pipeline infrastructure across Australia,” Mills said at the time. “I will continue to drive the agenda for a national energy policy incorporating the connection of a national pipeline grid.”
That call has now been taken up by Australia’s largest pipeline operator APA Group, manager of 14,120 km of pipeline infrastructure. One of APA’s assets is the 1,600 km Amadeus Basin to Darwin gas pipeline, which was the world’s third-longest when it was completed in 1986 at a cost of just A$380 million.
“I would be personally disappointed if connection to the east coast grid doesn’t become a reality within about a decade,” APA Group CEO and Managing Director Mick McCormack told an Australian Pipeline Industry Association dinner in Darwin July 18. The connection would be via a 700 km pipeline joining existing gas infrastructure in the Northern Territory and Queensland.
“From a security of supply perspective it is an important connection,” he added. “The NT’s current gas supply from the Bonaparte and Amadeus Basins is sufficient to meet existing demand but new supply will be required post 2020 to support market demand. This will be particularly important if the Gove pipeline connection proceeds. Or, if northern shale gas resources are developed, this connection would provide a route to eastern markets.”
McCormack’s calls were supported by the Australian Pipeline Industry Association, which said the connection would provide increased energy security for both the Northern Territory and eastern Australian markets, as well as enabling access to prospective shale gas basins in Northern Australia.
“Projects like this have the potential to unlock the development of Australia’s unconventional gas reserves and increase the supply of gas to our largest local markets,” said APIA Chief Executive Cheryl Cartwight.
A raft of international oil and gas industry heavyweights have taken a foothold in northern and central Australia’s nascent shale sector over the past few years. Companies including Chevron, ConocoPhillips, Statoil, Total and BG Group have secured farm-in agreements and pledged investments of more than $1.55 billion in Australian shale, according to the US Energy Information Administration. The EIA has estimated that Australia has 437 Tcf of technically recoverable shale gas reserves, ranking the country sixth highest in the world.
The attraction in connecting those potential reserves to markets in eastern Australia is growing ahead of the impending startup of three CSG-to-LNG export plants currently under construction in the Queensland port city of Gladstone. Gas production in eastern Australia will need to rise from the current level of around 600 petajoules/year to about 1,500 Pj/year in order to supply those plants after they start producing in 2014 and 2015.
The startup of the Gladstone plants will coincide with the roll-off of 90% of major gas supply contracts in New South Wales, leaving consumers there facing the prospect of much higher prices and a shortage of supply. Eastern Australian gas prices, which have historically been low at around $3-4/Mcf, are now heading for export-parity levels of around $10/Mcf.
“Anyway you wish to slice it the potential reserves of shale gas and tight gas across Australia is huge — which may require very large markets for gas to justify commercial development,” APA’s McCormack said last week. “It would be disappointing, from a domestic gas supply point of view, to think that the only scale large enough would be the exporting of LNG as is going to happen shortly from Gladstone in Queensland.”
McCormack called for consideration of a policy similar to Queensland’s setting of minimum targets for gas generation. With the development of New South Wales’ estimated 11 Tcf or more of CSG stalled for now due to regulatory hold-ups and community opposition, and with consumers there facing increasing uncertainty over supplies post-2016, such a policy might not be required to finally get a trans-Australia pipeline project up and running.