The world may run on oil, but the oil industry runs on capital, and for US shale producers that capital is starting to dry up.

Earlier in the year it was still relatively easy for US exploration and production companies to raise capital by selling debt or equities, in spite of last year’s oil price crash caused by a global glut. Now those sales have slowed sharply, and the financial strain on the industry is growing.

The next turn of the screw is approaching, in the shape of another round of redeterminations of “borrowing bases”: the valuations of companies’ oil and gas reserves used by banks to secure their lending.

The shale industry, which has been responsible for rapid growth in US oil production since 2009, is not about to die. There are plenty of strong companies that have healthy balance sheets, low costs, or both, and they should be able to ride out the downturn. But there are very wide differences in resilience between companies. Those with high costs or high debts, or both, face a turbulent future.

“In retrospect, easy money and a difficult time for finding the right thing to invest in led to an overshoot in US [oil] production growth,” says Edward Morse, global head of commodities research at Citigroup. “Companies that should never have been brought to life were brought to life.”

Now that overshoot is heading for a correction. Analysts expect a wave of asset deals, acquisitions and corporate bankruptcies, as weaker companies struggle to avoid collapse, not always successfully.

Already 16 US oil production companies have defaulted this year, according to Standard & Poor’s, the rating agency.

The biggest failure has been Samson Resources, which was bought by a consortium led by KKR in 2011 for $7.2bn, and said last month it intended to seek bankruptcy protection in September.

There are eight oil producers with credit ratings of triple-C or lower, meaning that “they’ve got about a year or less before they burn out of cash”, says Thomas Watters, a managing director at S&P.

The next hurdles facing many of those companies will be their borrowing base redeterminations, which typically take effect on October 1.

The previous round in March and April was less brutal for the companies than some had feared. This one is likely to be significantly tougher, draining liquidity away from struggling companies.

Since the spring, expectations that oil prices might rebound have quickly faded, meaning that banks will be using lower assumptions when valuing reserves.

The banks are also being warned by the Office of the Comptroller of the Currency, the federal regulator, to watch out for the risks involved in lending to oil and gas companies, prompting fears that loans could be withdrawn from businesses that would be financially viable if they were given a little more time.

Mark Sadeghian of Fitch, the rating agency, argues that banks will again try to avoid cutting back their lending too sharply. “We don’t expect anything cataclysmic,” he says. “It makes sense for banks to broker a deal, as opposed to driving companies to the wall.”

Even if they keep fragile companies alive, though, the banks are still likely to want to cut their lending, he adds.

Buddy Clark, chair of the energy practice at Haynes and Boone, a law firm, says that when companies announce their new borrowing limits, investors should make sure they read the fine print. In some cases borrowing bases will be set at a comfortable level, but could be scheduled to reduce over six months, or have a shorter review period.

“The hope is that the market will pick up in time to allow them to sell equity to shore up the balance sheet,” says Mr Clark.

As companies seek to persuade investors and banks to back them, their costs are critical. Under pressure from the slump in the prices of both oil and natural gas, US exploration and production companies have achieved remarkable feats in cutting costs — in some cases by as much as 25 per cent — and raising productivity.

EOG Resources, the first company to produce shale oil successfully, said last month that it had reduced the cost of drilling a well and starting production in the Eagle Ford formation of south Texas to $5.5m, down from $6.1m last year, while making it yield more oil.

Whiting Petroleum, the largest producer in the Bakken formation of North Dakota, said earlier this month that “enhanced completions” — using higher volumes of sand when fracturing wells to release oil — could raise production by 40 to 50 per cent while increasing costs by only 15 per cent.

However, the sector is a heterogeneous group. A recent study found that the oil producer with the lowest full-cycle cost per barrel — a measure that combines the expense of extracting crude plus the investment needed to replace reserves — was Seven Generations, at about $20. The highest-cost producers were Breitburn Energy Partners and Denbury Resources, at about $70, according to Moody’s, the rating agency responsible for the study.

The median full-cycle cost per barrel was about $51 for oil-focused companies, implying that at present prices of about $46 for US crude, more than half of the producers are losing money.

Eventually, supply and demand in the global oil market are expected to come back into balance, sending crude prices higher. US oil production is already falling, according to the government’s Energy Information Administration, reflecting the 58 per cent drop in the number of rigs drilling for crude since last October.

But this rebalancing of the market could be a lengthy process. While it is working through, more US shale producers are sure to fall by the wayside.