New year draws giant’s focus to WA and US assets

newINDUSTRY giant BHP Billiton looks set for a busy year as it considers best options for developing a remote field off WA, and its US shale assets start to pay off.
The Scarborough field was discovered off the WA coast in 1979, about 220km north of Exmouth, and is considered one of the most remote resources in the Carnarvon Basin, with an estimated 8 trillion cubic feet of dry gas.
Despite joint venture partner ExxonMobil expressing interest in a floating LNG (FLNG) concept for the field, BHP Billiton Petroleum president Tim Cutt has extinguished ideas the development would definitely use the technology.
Mr Cutt told the ABC the company would look at other options first.
“We’d really like to look at existing infrastructure to see if we can leverage existing infrastructure,” he said. “So where that infrastructure is not available I’d say FLNG will have a place.”
Last month the joint venture was given the go-ahead by the Federal Government to plan an FLNG operation, but would still need approval for the development concept, front end engineering and design work.
The two companies have spent the last three decades considering how to develop the remote field, due to a lack of infrastructure. Ten years ago BHP proposed an onshore plant near Onslow, but the concept never reached fruition.
ExxonMobil proposed an FLNG vessel for Scarborough that would process about 7 million tonnes per annum of LNG from five processing trains.
Meanwhile, BHP’s shale gas assets will start earning money in the next financial year before generating about US$3 billion of free cash flow by 2020. BHP has about 1.5 million combined net acres in Texas, Louisiana and Arkansas in the Eagle Ford, Permian, Fayetteville and Haynesville basins.
The company’s assets were expected to have a production life of 50 years. Mr Cutt said the US shale business would produce 500,000 barrels of oil equivalent per day in the 2017 financial year.
“Consistent with our strategy, we continue to evaluate and strengthen our acreage position as we seek to extend our liquids production profile,” he said.
“Our evaluation program in the Permian has successfully identified a focus area where we are actively pursuing a 100,000 barrel of oil equivalent per day development.”
The turnaround for cash flow was due to lower drilling costs, quicker drilling and higher oil recovery rates, Mr Cutt told US analysts.
“We have been able to reduce drilling times and costs for our Black Hawk wells (in Eagle Ford) by as much as 30 per cent,” he said.
“In some cases, production from individual wells has increased by as much as 50 per cent over their expected average.”
In the 2014 financial year about 75 per cent of onshore US drilling would be focussed on Eagle Ford shale and the company said it would take a depreciation charge of about US$600 million in the Permian Basin.
The company expected to produce about 250 million barrels of oil equivalent with about 114mmboe from its onshore US assets in the 2014 financial year. BHP anticipated the US gas market would supply 11 per cent of Asian demand by 2030, which is less than half of the predicted 25 per cent supplied by Australia.