INSIDE the boardrooms and bars of Houston, the spiritual capital of America’s energy industry, the swagger is back. The oil price may only be at $48, or half the level it was three years ago. But shale fracking—the business of getting oil and gas out of rocks by blasting them with water and sand—is booming once again after the crash of 2014-16. Exploration and production (E&P) companies are about to go on an investment spree. Demand is soaring for the industry’s raw materials: sand, other people’s money, roughnecks and ice-cold beer.

Shale’s second coming is testament to Texan grit. But the industry’s never-say-die spirit may explain why it has done next to nothing about its dire finances. The business has burned up cash for 34 of the last 40 quarters, according to figures on the top 60 listed E&P firms collected by Bloomberg, a data provider. With the exception of airlines, Chinese state enterprises and Silicon Valley unicorns—private firms valued at more than $1bn—shale firms are on an unparalleled money-losing streak. About $11bn was torched in the latest quarter, as capital expenditures exceeded cashflows. The cash-burn rate may well rise again this year.

Meanwhile, the prospect of rapidly rising production is rattling global energy markets. In particular it worries OPEC, a cartel of producers led by Saudi Arabia that aims to restrain output and keep prices stable and fairly high. Khalid al-Falih, Saudi’s energy minister, warned of “irrational exuberance” on March 7th during an energy-industry conference in Houston.

When oil prices halved in just 16 weeks starting in late 2014, panic hit Texas, followed—for a while—by grim austerity. The number of drilling rigs in America dropped by 68% from peak to trough. Companies slashed investment. Over 100 firms went bankrupt, defaulting on at least $70bn of debt. Shale’s retrenchment helped to stabilise the global oil price. Production in the lower 48 states (ie, excluding Alaska and Hawaii), and excluding federal waters in the Gulf of Mexico, has dropped by 15% over the past 21 months, equivalent to 1m bpd, or 1% of global output.

The partial recovery in the oil price, which at one point fell as low as $26, is only one factor behind renewed enthusiasm for shale. Houston’s optimists also argue that the full geological potential of Texas’s Permian basin has only just become apparent. Some experts think it could in time produce more barrels each day than Saudi Arabia does. That has offset gloom about falling production from other shale basins, such as the Bakken formation in western North Dakota. The industry has also lifted productivity. Drilling is faster, more selective and more accurate, and leakage rates are lower. Wells are being designed to penetrate multiple layers of oil that are stacked on top of each other.

But the fact that the industry makes huge accounting losses has not changed. It has burned up cash whether the oil price was at $100, as in 2014, or at about $50, as it was during the past three months. The biggest 60 firms in aggregate have used up $9bn per quarter on average for the past five years. As a result the industry has barely improved its finances despite raising $70bn of equity since 2014. Much of the new money got swallowed up by losses, so total debt remains high, at just over $200bn.

Oil bosses like to show off their newest wells in the Permian basin, which, they say, can now make internal rates of return of more than 50% over their working lives. But most firms have mediocre wells too, as well as corporate overheads, so their overall efficiency improvement has not been great. For the ten largest listed E&P firms, aggregate cash operating costs per barrel fell by $13 between 2014 and 2016; not enough to offset a $50 drop in the oil price. Because shale-energy fields run out far faster than traditional ones, firms must reinvest heavily to keep production flat.

It is instructive to compare shale with another natural-resources business that has had to cope with a collapse in commodity prices. In 2016 the mining industry’s biggest companies ground out profits, produced cashflow after capital investments and made a decent return on capital. Yet despite this unflattering contrast, capital investment by American E&P companies will probably soar over the next year, by perhaps 50% or more.

There are two theories for why this is happening. One is that the way in which executives are paid, together with lenders’ incentives, means that Houston is always vulnerable to investment mania. Not one of the ten biggest E&P firms, for example, puts significant emphasis in its pay scheme on how much return on capital it produces. Low interest rates make it easy for shale firms to borrow, and fee-hungry banks cheer on the spectacle. But the only way that the mania will end well is if oil prices rise sharply, bailing out the industry, or if E&P firms are bought by bigger energy firms. That is possible, but companies such as Exxon and Shell are too seasoned to pay a lot for small, unprofitable firms.

Houston, we still have a problem

The second explanation is oil executives’ belief in increased output from the Permian, and higher productivity. Most E&P firms reckon they can expand production at an annual rate of 10-20% over the next few years. But to justify their market values, and make an adequate return on their cumulative capital invested, listed E&P firms would over time need to make about $60bn of free cashflow each year. Assuming that both energy prices and capital spending stay flat, that would require them roughly to double production from current levels.

The trouble is that this is a circular argument. If achieved across the whole shale industry it would mean that output would be twice as high as it is now, leading to a 5% increase in global supply, which might in turn lower the oil price. There is something heroic—and baffling—about America’s shale firms. They are the marginal producer in a cyclical industry, and that is usually an unpleasant place to be. The oil bulls of Houston have yet to prove that they can pump oil and create value at the same time.