Mr Cutt told a conference in New York that the US onshore business should be a strong contributor to pre-tax profits this financial year, following on from a profitable second half of 2013-14.

The business, which is swallowing up about $US4 billion a year of capital expenditure, should then be cash-flow-positive by 2015-16, and be throwing off towards $US3 billion a year in cash by the end of the decade.

BHP's shale business, built from $US20 billion of acquisitions in 2011, suffered a writedown in some of its gas assets the following year after US gas prices slumped. However, the division has driven significant growth for the petroleum business, mostly due to the lucrative Eagle Ford shale activities in southern Texas, and promises to deliver more from the emerging Permian shale play in the west of the state.

The emphasis of the growth in the shale business comes after BHP last month said it would review its smaller petroleum assets for sale as part of a comprehensive overhaul of its portfolio centred around a demerger. The high-returning oil and gas business will remain with BHP, becoming a bigger part of the pared-down portfolio.

In his speech in New York, Mr Cutt revealed that BHP, which sold its British venture in Liverpool Bay last year, was actively marketing its petroleum assets in Pakistan while other smaller assets around the world were under review and could be divested.

Mr Cutt said BHP would prioritise the highest-return opportunities in petroleum, with a near-term focus on deep-water in the Americas, and the shale liquids business. However, its "greenfield LNG" business, which includes the huge undeveloped Scarborough gas field operated by ExxonMobil off Western Australia, appears to be lower priority.

"The takeaway for you guys today is that we will not move forward with these projects unless they are economically attractive and, more importantly, they are competitive within the overall portfolio," Mr Cutt said.

Similarly, the expansion of the Mad Dog oil venture in the US Gulf of ­Mexico, operated by BP, is still under scrutiny, after last year's decision to rework the development plan to cut costs that were set to reach towards $US20 billion, on some estimates.

BHP has earmarked about $US1.5 billion a year on capital expenditure in its conventional oil and gas assets, primarily in the Gulf of Mexico and Australia, as it seeks to maintain stable production from that part of the business.

Mr Cutt was very enthusiastic about the potential for BHP's new deep-water play in Trinidad, where it has identified a giant oil prospect, Pegleg, which is bigger than the large Shenzi, Mad Dog and Atlantis fields in the Gulf of Mexico. Pegleg lies in the Orinoco River Basin, which Mr Cutt said was "one of the last large deltaic basins" to be explored in deep water.

A major seismic survey in the Trinidad acreage is due to be completed by the end of this year, with about 12 months of studies to follow before drilling.

"We are very excited about Trinidad," Mr Cutt said. "We have a large position, and we hope it will be another heartland for us."

Deutsche Bank energy analyst Paul Young said it looked as if BHP was "hanging its hat" on Pegleg to some extent, and probably needed to add more acreage, though he noted the company had recently outbid some majors including BP for several new exploration permits in the western part of the Gulf of Mexico.

"It clearly looks like BHP is stepping up in a big way" in its exploration in the Gulf, he said. "It certainly tells you they are focusing more on offshore."

In the US shale business, BHP is continuing to focus on liquids-rich areas, which were prioritised for drilling after the slump in gas prices. Mr Cutt said that while the Haynesville shale activities could reap 30 per cent returns, BHP was working to improve its fracking technology before moving into full development.

The prized Black Hawk venture in the Eagle Ford shale in southern Texas was set to become BHP's largest single producing petroleum asset this year and was generating margins of some 75 per cent at current prices, Mr Cutt said.

However, he signalled that the earlier-stage Permian play in western Texas could become even more significant for BHP, noting the company's 74,000 acres in its core area, larger than the 57,000 acres in the Black Hawk.

"We know what kinds of returns the Black Hawk is delivering so we feel good about this," Mr Cutt said, describing the Permian as "fantastic".

He made public for the first time that BHP is focusing its work in the Permian in the Wolfcamp shale, which Mr Young said contrasted with some other companies targeting different rocks.

BHP reiterated its target of building a 100,000 barrels of oil equivalent per day business in the Permian by the end of the 2018 financial year.

"The well results to date are positive and repeatable and there is additional upside to the development program given our longer-term outlook for the field," he said.

However, Mr Young said he expected BHP would have to deploy more drilling rigs in the Permian in 2015-16 and potentially form some joint ventures or add acreage to reach its production target.

Mr Cutt said BHP's efforts to drive productivity in drilling were paying off, with some wells in the Black Hawk now costing less than $US2 million each, down from an average of $US5.5 million in 2012-13. Wells in the Permian were more difficult but costs had fallen from $US7 million two years ago to $US4 million in some cases.