From atop Houston’s skyscrapers you can see evidence of the good times just gone. New towers are still being erected all around the city centre, a lagging indicator of the energy boom that ended abruptly in mid-2014 when the price of crude in America dropped from $100 to $43 (today it is around $57). The victims of that crash are harder to spot. “Look! Over there!,” says an oil man, pointing down at the offices of Goodrich Petroleum. A midsized exploration firm specialising in shale oil, its share price has collapsed, its debts are six times as big as the market value of its equity and it does not currently have any rigs in operation. (Goodrich says it has ample liquidity and may sell assets to raise funds.)

At the start of 2015 it seemed that there would be a lot more firms like Goodrich. When OPEC, the oil cartel led by Saudi Arabia, decided to keep pumping oil, it hoped that lower prices would irreparably damage the finances of America’s shale-oil companies. They have revolutionised the energy industry, using junk bonds and a technique known as fracking—that blasts water, sand and chemicals at rock to release oil and gas—to boost America’s share of global oil production from 8% a decade ago to 13% today. Yet six months after the oil-price slump only five firms out of the hundreds in the shale-drilling business have gone bankrupt.

American oil production has actually risen slightly, reaching 9.6m barrels per day in June. Output of shale gas, the other component of America’s fracking revolution, is holding up, too. In Houston oil men proudly declare victory: the Saudis have failed to put Texas out of business.

The industry argues that the past six months have shown its true grit. Before shale came along the oil industry relied on mega-projects. Kashagan, in the Caspian Sea, involves one autocrat, ten man-made islands, 20 years of toil and $50 billion—and has yet to deliver the Western firms who bet on it more than a drop or two of oil. In contrast the typical shale well costs just $10m and can be producing within a matter of months. That means the industry can adapt fast. Since December shale firms have cut costs by 20-25%, according to Bob Brackett of Sanford C. Bernstein, a research firm. This has been achieved by brutally squeezing the oil-services firms that provide them with rigs, pumps and staff—big services companies such as Halliburton have fallen into losses and small ones are on life support.

The shale producers have also cherry-picked which wells they drill, concentrating on the best prospects and fine-tuning their engineering methods. As a result the number of rigs active in America has dropped by half since the start of the year.

This era of frugality can be seen in Midland, a Texan town in the Permian basin, one of six big shale areas (see map). Midland has witnessed multiple booms and busts since the 1920s. Graced by Ferraris during the 2012-14 boom, its highways are now populated by pickup trucks. Some 20,000-30,000 temporary workers have left. On the town’s outskirts idle equipment is being auctioned off at 20 cents on the dollar, burrito vans ply a dismal trade and the static-caravan parks advertise vacancies. Yet viewed from a plane Midland is surrounded by wells as far as the eye can see, most still busy pumping.

The shale industry’s dazzling response to low prices—austerity combined with growing production—has enthralled Wall Street, which has continued to supply shale firms with an abundance of their most vital raw material, capital. So far this year oil-production firms have raised $15 billion of equity and $20 billion of bonds, helped by frothy markets, a near-zero Fed Funds rate and a partial recovery in the oil price. Even Goodrich, the troubled firm in Houston, managed to issue in February $100m of “second-lien” debt, which is secured against assets, at an 8% interest rate. Most firms have paid far less than that on new debt. The buyers of these securities are mainstream investors on the hunt for yield, but also distressed-debt funds that were set up in early 2015 to pick over the carrion of the shale industry. They have found fewer carcasses than expected and instead are bidding up prices.

Exuberant when oil prices were high and resilient when they are low, the shale industry appears unbeatable. Yet just how good are its finances? The Economist has examined the books of the 62 largest listed exploration and production (E&P) firms in America whose collective output is mainly from shale. The results (see charts) suggest many firms are more vulnerable than the bullish noises from their bosses suggest. There are three sets of concerns: the juicing-up of the results announced for the first quarter of 2015; high leverage; and the industry’s returns on capital.

First, consider the juicing-up of performance. During the quarter to March the industry reported aggregate cashflow from operations of $15 billion—this is the money the business throws off before capital expenditure and financing activity. But this reflects the benefit of derivative hedges taken out in 2014 when oil prices were much higher, and which in most cases will largely run out over the course of the next year or so. Exclude derivatives, and cashflow was 31% lower. Almost half of firms, accounting for 1% of global oil production, relied on transitory gains from derivatives for over half of their cashflow.

All firms have slashed their capital-investment budgets for 2015—a reduction of a third is planned in aggregate. Having traditionally invested far more cash than it generates, financing the gap with debt, the industry is keen to show it can live within its means. Yet while promising cuts it continued to spend heavily in the first quarter, to the tune of $35 billion, about the same as a year earlier. Were the industry to have balanced its books (excluding the benefit of hedges), capital investment would have needed to be 70% lower. Capital investment feeds through to production volumes with a lag of 3-9 months. Today’s healthy production figures are no guarantee of future bounty.

The second concern is a deep well of debt. Listed E&P firms owe $235 billion and during the first quarter debt rose, reflecting continued heavy spending. Assume a firm is in trouble if its net debt is more than eight times its annual cashflow from operations (based on the annualised first-quarter figures and excluding the benefit from derivatives). On the basis of this snapshot, 29 of the 62 firms are distressed, owing a total of $84 billion. Listed shale firms with distressed balance-sheets account for 1.1m barrels a day of oil production, or 1.2% of global oil production.

The final worry is the returns on the $570 billion of capital the industry has invested. David Einhorn, a noted shortselling fund manager, has said frackers are bottomless pits. In most industries returns can be gauged by comparing a firm’s capital to its “steady state” cashflow, after deducting the capital spending needed to maintain its assets. This is how Exxon and Shell measure the value they create. But this approach does not work for shale firms: rather than husbanding long-term assets, like conventional oil firms, they are constantly investing in creating and depleting a whirl of ephemeral assets. If conventional oil firms are like ranching, shale is a rodeo.

Notwithstanding this, it is fairly clear that listed shale firms are unable to earn a fair return on the historic capital they have invested at the current oil price. Based on the first quarter (excluding derivative gains), their overall annualised return on capital was 8%, before any taxes or any capital investment. After deducting a rough guess at the capital investment required to keep production flat in the short term, returns on the historic capital invested fall to zero. Some 55 of the 62 firms, accounting for 4% of global oil production, are making inadequate returns, by our reckoning.

Despite this dismal snapshot, investors value E&P firms at more than their capital employed. This could mean they think costs will fall further or that oil prices will rise. But they may also expect the drilling firms to get better at identifying profitable new investments than they were during the boom. Most shale firms say that by being thriftier and more selective they can earn annualised returns of 25% or more on new wells at $60-a-barrel oil. Reinforcing their optimism, there is a buoyant secondary market for new wells once they are producing, with pension funds and tax-free investment vehicles the buyers. An E&P firm active in the Eagle Ford basin, in Texas, says it can sell newly drilled wells for 1.4 times their cost. Sceptics grumble that they have heard it all before.

The oil industry, among other things, is betting on higher prices. Bulls can think of plenty of arguments to support their case, from a stronger economic recovery in America to violence and instability in the Middle East. The futures market is predicting only a modest recovery. Having risen from its low-point of $43 in March to $57 now, West Texas Intermediate will rise to $66 by 2019, the market is indicating.

Meanwhile as the debate over the economics of shale rages in America, capacity is being cut elsewhere, particularly in projects with high production costs, from deepwater drilling in places like the Arctic or Canada’s oil sands. Of the worldwide investment cuts by listed energy firms expected to happen by 2016, only about half are forecast to come from shale, according to Oswald Clint, also of Bernstein.

In Texas and North Dakota oil men secretly dream that the global supply of crude will shrink without shale declining. The biggest oil firms, which have vast reserves of cash, are continuing to invest heavily in shale. In May ConocoPhillips, which says it has some of the lowest-cost shale properties in America, committed to invest $3 billion a year and forecast rising production up to 2017. By this account America’s smaller E&P firms are being astute: they are using their derivatives hedges and their mastery at raising capital on Wall Street to bridge a difficult patch. When oil prices pick up later this year they will start investing even more heavily in growth, but with leaner cost bases. In a decade’s time the 2015 oil-price dip will seem as transitory as that in 2009 during the financial crisis.

But there is another, less rosy scenario for America’s shale barons. Oil prices may remain flat. Towards the end of this year their hedges run out; shale-oil production dips markedly as the lagged effect of capital-investment cuts kicks in. (Output has already dipped in the Bakken basin in North Dakota.) With growth evaporating and cashflow faltering it becomes harder to sell shares—the pace of capital-raising has indeed slowed in recent weeks. The junk-bond market becomes jittery and E&P firms start to worry about refinancing the $66 billion of debt and interest that is due in 2016-18. As firms’ oil-reserves estimates are marked down to reflect lower prices, banks cut their loans, which they typically tie to reserves figures.

In this eventuality, indebted shale firms would slip into crisis. This being America, their fields would keep pumping as their balance-sheets were restructured. Their assets would be sold, probably to the bigger E&P firms or global majors. But there might still be a dip in the 1-2% of global oil supply that they account for, and as their reserves deplete they might not be entirely replaced. There would be a bad-debt problem among banks and investors.

Shale energy is here to stay. There are a lot of rocks and clever people between the Redwood forests and the Gulf Stream waters. The industry has proved its entrepreneurial spirit and its skill in both geological and financial engineering; and its new investments are likely to earn better returns than past ones. But not all shale firms will survive. If oil prices do not rise soon then their viability will deplete even faster than their wells.

Source: www.economist.com

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