Australian shale potential No 1
Australia is still rated the best country in the world to walk the well-trodden path of North America's shale revolution with the Cooper Basin the best bet to emerge as the most prolific unconventional hydrocarbon producing region in the country. The cautionary note, however, is cost,
This is the verdict of Hong Kong based Bernstein Research analyst Neil Beveridge's recent report investigating the pros and cons of Australia's latent, but rapidly developing, shale gas and oil resources.
Beveridge concludes that Australia's potential to develop its shale industry as swiftly as it moved into coal seam gas to LNG projects has to be seen against the background of spiralling cost challenges threatening to curtail the fraccing induced phenomena.
“Above-the-ground factors matter when it comes to shale and Australia has many similarities to North America,” Beveridge said. “Australia is a large country, with low population density and a developed fiscal and regulatory oil and gas regime which will be supportive of shale exploration and development.”
Critically, Beveridge says an Australia climate conducive to foreign investment is an essential ingredient for capital expenditure, with a dynamic small cap exploration and production sector willing to take exploration risks adding to the country's attractiveness.
This reality was reflected in five international E&P companies farming into Australian shale plays last year with investments totalling nearly US$700 million, including: Norway's Statoil investing US$210 MM in Petrofrontier's southern Georgina Basin acreage; BG's US$130 MM joint venture with Drillsearch; a US$152.40 MM deal between Mitsubishi and Buru Energy; ConocoPhillips' US$107.40 MM agreement with New Standard Energy and a US$60 MM joint venture between Hess Corporation and Falcon Oil & Gas in the Beetaloo Basin.
Beveridge predicts additional US farm-in activity, which he said served the dual purpose of providing capex essential for exploration, while bringing North American shale expertise to Australia.
With shale exploration activity occurring in five of 20 onshore basins, the flip side to a barrel half full of Australian shale optimism is the challenge of high costs, lack of equipment (notably rigs and fraccing spreads), water issues and restricted domestic gas markets that threatened to put the brakes on exploration endeavours.
Beveridge said higher value liquids will prove critical in offsetting higher costs in Australia: “With a limited domestic gas market, high costs and excess conventional gas reserves, dry gas plays will only work in eastern Australia where there is infrastructure capacity and market. Some basins appear more liquids prone than others and liquids will be a key factor in separating viable from non-viable shale plays,” he said.
While Bernstein rates the Cooper Basin Roseneath-Epsilon-Murteree shale as the most “likely to work”, early well tests showing flow rates from shale of 2 MMcf/d or lower meant wellhead gas prices would have to be US$6-8/MMcf to be economically viable.
“While it remains too early to tell who will be the winners in the race for Australian shale, we favour E&P (companies) with exposure to the Cooper Basin, and particularly exposed to acreage in the flanks of the Nappamerri trough where the REM shale is liquids mature,” said Beveridge.
Beveridge described the liquid shale plays in Western Australia's Canning Basin and the Northern Territory's Beetaloo and Georgina basins as, “Highly speculative given their geological age and lack of historical conventional production, but the upside could also be enormous.”
“While the risk is high, the enormous potential of these plays plus valuations of less than $100/acre makes the risk-reward balance interesting, in our view,” he said.