AGL said in an investor presentation yesterday that it had already identified a number of sites for importing LNG as a “fourth option” beyond the three existing ones for security of supply, even as Australia is on track to overtake Qatar as the world’s largest LNG exporter by 2018.

AGL’s three existing options are continuing to negotiate with Cooper and Gippsland Basin producers for long-term competitive supply, expand domestic supply or look at increased storage options.

The new option is to import LNG from Asia, Europe, the Middle East or the US and convert it back to gas at a floating storage and regasification unit stored at a southeast port connected to the east-coast gas market.

Regarding expanding domestic supply, AGL cited the binding heads of agreement it executed with Cooper Energy to support final investment decision on the Sole gas field development, which is targeted for early 2017.

AGL said it had a “significant” storage position in Iona, with peak storage in Newcastle, New South Wales, and Silver Springs, Queensland, which positions the company for seasonal demand.

However, it gave prominence to the fourth option, and revealed it was investing $17 million to ready the project for a final investment decision in 2018-19, with potential development costs of between $200 million and $300 million.

The company will start engaging regulators and communities early next year.

AGL also charted what it believes to be an ever-growing gas shortfall in the absence of further development, citing Australian Energy Market Operator-forecast domgas demand to shoot above 1800 terajoules per day by 2034, with Surat-Bowen Basin contingent resources languishing at around 600TJpd and conventional gas resources at just above 200TJpd.

Surat-Bowen contracted gas is expected to disappear by about 2032.

While AGL managing director Andy Vesey said he hoped to take advantage of the current supply-demand imbalance in LNG spot markets, the global glut is widely forecast to wind up by the time the company wants to start importing.

However, he indicated that prices could stay relatively low with US shale-derived exports continuing to flood the market. Other projects also inching towards sanction and operation in Canada could also keep gas prices low.

Prediction

One day after Victoria’s Labor government decided to permanently ban hydraulic fracturing and unconventional gas extraction and extended the moratorium on the exploration and development of even conventional onshore gas until 2020, RISC’s Perth-based principal Martin Wilkes renewed speculation about the likely need for LNG imports.

He said the Northern Gas Pipeline, being developed between the Amadeus Basin in the Northern Territory and Mt Isa in Queensland, would “at best” deliver about 100TJpd of gas into the eastern states’ main gas markets, which are more than 2000km away.

“This is only equivalent to about 5% of the eastern states supply needs, and is unlikely to have significant impact,” Wilkes said.

“A well-positioned LNG import facility could supply more than 500TJpd, 25% of the market requirements, directly into the markets.”

During the LNG18 conference in Perth in April, two of Deloitte’s top oil and gas analysts Geoffrey Cann (then Brisbane-based, now returned to Calgary) and Houston-based Andrew Slaughter said LNG imports were perfectly realistic given Queensland can’t mitigate the east coast energy crisis alone.

Those comments were hot on the heels of Australian Competition and Consumer Commission’s inquiry into the east coast gas market which recommended the drilling restrictions in New South Wales, Victoria and Tasmania be scrapped.

Cann said building an LNG receiving terminal in Sydney was “certainly not inconceivable”, as it’s not without precedent for other countries to both import and export LNG.

“Brazil both ships and imports LNG as it needs to balance its market out and has challenges trying to get its gas domestically. It could easily be said that the same phenomenon is starting to appear on the east coast of Australia,” Cann said.

Cann also warned that Queensland, despite being the only east coast state “open for business”, is too slow in its approvals processes to save its southern neighbours’ energy crisis in time.

Cann said it would take 14 years from applying for a license to producing first gas in Queensland, and $100 million would be spent in the process.

Shell Australia chairman Andrew Smith also said earlier this year that NSW restrictions could open the door for LNG imports.