AUSTRALIAN companies that looked to strike it rich over the last five years in the once-booming US shale industry have been selling up licences, slashing drilling activity, and in the most dire cases cutting board and executive salaries as they hunker down in an attempt to ride out an uncertain period of depressed prices.

The values of ASX-listed players Antares Energy, Sundance Energy, and Empire Energy have more than halved since the beginning of July when oil prices tipped over the crest and began galloping southward.

Austin Exploration’s price is a third of its mid-2014 price, while Sun Resources has been smashed to a point where its value is a ninth of where it was in July.

AusTex Oil, Maverick Drilling and Exploration, and Molopo Energy performed slightly better – enduring less severe share price hits – though it should be noted the latter sold up its last North American operations in January.

WA-based Red Fork Energy remains the only Australian shale player to have fallen over as a result of betting on a sustained high price – entering receivership in December – but a climate of deep uncertainty has left many wondering who is next.

“In the shale oil plays, the activity is retreating to the core,” University of Western Australia professor of resource and energy economics Peter Hartley said of sector activity.

BHP Billiton announced in January that it would cut its rig numbers in the US by as much as 40 per cent by mid-2015 and said it expected to be hit with impairments of up to US$250 million.

The company’s 26 shale rigs will reduce to about 16, with operations to be focused on its liquids-rich Black Hawk acreage.

Having dived head on into the US gas sector in early 2011 with the multibillion dollar purchase of Chesapeake Energy’s Fayetteville shale gas assets, by August 2012 the company had written down the gas assets significantly as a result of the US gas price plunge, instead shifting focus to liquids-rich plays in the Permian and Eagle Ford basins.

The BHP story reflects the importance of distinguishing between the two subsectors in the US shale industry – dry gas and the wet gas or tight oil sector – with the latter now experiencing its oil price-prompted shock, following the earlier hit to natural gas prices.

While BHP has re-directed its resources away from the flooded, low-return gas market, a number of the small and medium Australian players remain exposed to the low gas prices, as well as enduring the more recent oil shock.

Dr Hartley said his research on the US shale gas industry had shown the best gas wells could break even at US$2 per mmbtu, the worst sat at US$8-9 per mmbtu, while the average was about $US4.50.

He said producers had seen some offsetting benefits from costs falling by as much as 20% since the calculations were made, so the break even points had likely improved to an extent.

Dr Hartley said the lowest-cost gas plays were likely to be in Texas, while North Dakota projects tended to present a more challenging environment.

“North Dakota [would] take a bigger hit because it is much more interior whereas Texas is much closer to getting a price that’s going to be closer to the international price,” Dr Hartley said.

A Wood Mackenzie’s analysis of break even prices for US shale oil regions showed sectors of the Bakken and Eagle Ford dominated the top-ten lowest cost producers in the shale industry, where break even points were between about US$55 and $US70.

Dr Hartley said the situation was not so simple that it could be broken down basin-by-basin, or play-by-play, as reflected by other plays in the Bakken and Eagle Ford being represented at the highest-cost end of Wood Mackenzie’s scale – at over US$100 per barrel.

“There’s no one break even cost – there’s a whole range,” Dr Hartley said.

“There is basically a supply curve in every basin, there’s sweet spots and other parts of it where you need a much higher price to break even with respect to capital costs.

“There’s no one number really but it is also a bit of a moving target because of the costs of the inputs into the industry also adjust as the level of activity adjusts.”

North Dakota Petroleum Council spokeswoman Tessa Sandstrom said the industry faced lean times in the short term but the Bakken would remain a world-class resource over 25-40 years, helped by continuous technological advancements.

“It’s always important to remember that just a little over a decade ago the Bakken was considered uneconomic to produce,” Ms Sandstrom said.

Director of the University of Queensland’s Centre for Coal Seam Gas Andrew Garnett said operators without operating cash flow problems would shut in wells as they waited for a long, slow price build.

Dr Garnett said there would be interesting takeover opportunities for companies that are able to sit on assets without it affecting their ability to carry out their other operations.

“Those with a confident outlook will look to buy up the people who are suffering, and there will be an awful lot of people who are trying to shut-in and inevitably some people going out.

“Without a doubt those who are living on cash flow at the moment – and remember the unconventional operations require continuous drilling quite often – those plays will start to suffer.”

Most of the Australian companies invested in US shale announced budget cuts in late-2014 or early-2015, but some cuts appear to be not conservative enough, with the oil price plunging below predicted levels.

Lonestar Resources’ December spending downgrade was based on a West Texas Intermediate price of between US$65 and US$85 a barrel.

The company said it would revisit guidance in January if the price sunk below projected levels. The WTI price as at 28 January was US$46.79.

Similarly, former drilling contractor Maverick Drilling and Exploration, which entered the oil business proper in 2010, said it would run its Blue Ridge Dome play “at a lower level of activity consistent with US$75 per barrel revenue”.

Lonestar also announced it would drill 15-17 wells in 2015 rather than the projected 20-25, and said it would use its strong liquidity to consider asset purchases in its “targeted oil window” in the Eagle Ford in south Texas.

The company said its Eagle Ford operations continued to perform well, with costs totalling US$25 a barrel in October 2014.

Sun Resources reduced its stake in its Badger oil project in the Eagle Ford from 50% to 10% in November, saying the farm-out would enable it to focus its cash reserves on its Woodbine tight oil play.

In December the company announced managing director Matthew Battrick would receive a quarter of his salary in shares and its directors would receive only shares as payment for at least three months from 1 January.

The company said the transaction would enable it to focus its cash reserves on its operated activities in the Woodbine tight oil play in Madison and Leon counties.

In something of a sucker punch, compounding oil price concerns, Empire Energy’s US fracking ambitions were also hit by the decision to ban the technique in New York State.

In response, the company’s share price fell by more than half in a matter of days following the unexpected move.

Executive chairman Bruce McLeod played down the significance of the ban, saying affected Marcellus and Utica acreage was a “free upside” on existing acreage and was recorded at zero cost on the company’s books.

Sundance Resources announced it was obligated to drill six commitment wells to maintain its Eagle Ford acreage but would decrease expected spending by US$1.5 million to less than US$7 million per well.

Making its final moves to exit North American shale, Molopo Energy entered into an agreement to sell its final producing assets – the Fiesta acreages in Crockett Country, Texas – for US$1 million in January, with the company reporting the deal had avoided it paying for costly capital expenditure programs.

The operations were producing a paltry 161 barrels of oil per day during the December quarter and it was bleeding cash.

The company announced its attempts to divest its Quebec assets had failed and said it expected to surrender the permits this quarter.

Molopo blamed the ongoing moratorium on fracking in the region for the anticipated surrender.

With the Quebec departure, Molopo will have exited all North American operations.