About 600 people packed on to the Machinery Auctioneers lot on the outskirts of San Antonio, Texas, last week to pick up some of the pieces shaken loose by the oil crash.
Trucks, trailers, earth movers and other machines used in the nearby Eagle Ford shale formation were sold at rock-bottom prices. One lucky bargain hunter was able to pick up a flatbed truck for moving drilling rigs — worth about $400,000 new — for just $65,000.
Since the decline in oil prices began in mid-2014, activity in the Eagle Ford, one of the heartlands of the shale revolution, has slowed sharply. The number of rigs drilling for oil has dropped from a peak of 214 to 37, and businesses, from small “mom and pop” service providers to venture capital companies, are trying to offload unused equipment.
Terry Dickerson, Machinery Auctioneers’ founder, says sales doubled last year, in part thanks to the oil crash. Sellers are sometimes disappointed by low prices for oil-related assets, but they have to accept reality, he says. “I feel like a funeral director,” he adds. “I’m the one that has to tell them the bad news.”
The fire sale in Texas is just a small part of the worldwide value destruction caused by the oil decline. From Calgary to Queensland, oil and gas businesses are scrambling to sell assets, often at greatly reduced prices, to pay back the debts incurred to buy them.
Conventional wisdom has held that low oil prices tend to be good for equity markets and the economy, since cheaper fuel boosts profits and consumers have more cash to spend. But this decline has been different, with oil prices and stock markets often moving together. It is a reflection, some say, of worries about the destabilising effects of the industry’s mountain of debt.
From 2006 to 2014, the global oil and gas industry’s debts almost tripled, from about $1.1tn to $3tn, according to the Bank for International Settlements. The smaller and midsized companies that led the US shale boom and large state-controlled groups in emerging economies were particularly enthusiastic about taking on additional debt.
It was a classic bubble, says Philip Verleger, an energy economist. “It was irrational investment: expecting prices to rise continually. Companies that borrowed heavily when prices were high are going to have a very tough time.”
Borrowers and lenders alike were reassured by the consensus that the world had entered an era of persistently high oil prices. In June 2014, a barrel of Brent crude for 2020 delivery was $98. And central banks’ post-crisis monetary policies pushed investors towards riskier assets, including oil and gas companies’ equity and debt.
“Two things happened: we had high oil prices, and central banks had zero interest rates and quantitative easing policies,” says Spencer Dale, the chief economist of BP, who formerly held that role at the Bank of England. “That was a potent mix.”
From 2004 to 2013, annual capital spending by 18 of the world’s largest oil companies almost quadrupled, from $90bn to $356bn, according to Bloomberg data. The assumptions used to justify that borrowing were fuelled by a textbook example of disruptive technological innovation: the advances in hydraulic fracturing and horizontal drilling that made it possible to produce oil and gas from previously unyielding shales. The success of those techniques added more than 4m barrels a day to US crude production between 2010 and 2015, creating a glut in world markets that has sent prices down 65 per cent since the summer of 2014.
The expectations of sustained high prices have vanished: crude for 2020 delivery is $52 a barrel. Oil is now back to where it was in 2004, but most of the debt that was taken on in the boom years is still there.
In the past couple of months, the crisis has appeared to go into remission. Brent has crept up from a low point below $28 a barrel in January to about $41 on Monday. The global oil market, however, remains heavily oversupplied, leading many to assume that prices are going to stay below their previous peaks for many years. Even if oil prices remain at their present levels, the strain on many borrowers will be intense.
Standard & Poor’s, the credit rating agency, assesses oil companies based on an assumption of an average crude price of $40 this year. On that basis, 40 per cent of the US production and oilfield services companies it covers are rated B-minus or below. “B-minus is a very weak rating,” says Thomas Watters of S&P. “You don’t have a long lifeline.”
Some of the smaller US oil and gas production companies that led the shale revolution have gone bust; 52 have entered bankruptcy since the start of last year, according to Haynes and Boone, a law firm.
Linn Energy, one of the 20 largest US oil and gas producers, warned last week that it expected to breach its debt covenants. It has net debts of $3.6bn, but only $1m in borrowing capacity. Many US producers are now having their borrowing limits, which are based on the value of their reserves, redetermined by their banks. The falling value of those reserves means loan facilities will be cut back, leaving some companies without enough liquidity to stay afloat.
When oil and gas companies go into bankruptcy, there are often slim pickings for creditors. Quicksilver Resources, a Texas-based gas producer, went into Chapter 11 bankruptcy protection last year with about $2.4bn of debt. This year it announced sales of its US assets for just $245m, and some of its Canadian assets for $79m. Its creditors are on course for losses of about $2bn.
Even larger potential losses are lurking in some of the large state-controlled national oil companies in emerging economies, including PDVSA of Venezuela and Petrobras of Brazil, according to Moody’s, another rating agency. Both companies have large debt maturities looming in 2016-17: $12.6bn for PDVSA and $23bn for Petrobras.
In the US and Europe, banks have been quick to reassure shareholders that, while their losses are mounting, they are entirely manageable. French banks account for four of the 10 banks with the highest exposure. Crédit Agricole, whose $29.8bn credit exposure to energy is the second highest in Europe, has told investors that 84 per cent of the portfolio was investment grade. The disclosures were largely effective in soothing fears about energy debt.
However, the pace at which loan provisions is rising has been unsettling some. JPMorgan Chase told investors in mid-February that it would take another $500m charge to its reserves in the first quarter to cover likely losses on energy loans, a few weeks after it had said that it would take about $750m of charges for the full year.
Comerica, the Dallas-based lender, revealed in a regulatory filing last month that $75m-$125m of additional energy-related expenses would be recognised “primarily” in the first quarter — a departure from its previous guidance that the hit would be taken “particularly” in the first half of the year.
“It’s alarming that things are getting pulled forward so much,” says Julie Solar, an analyst at Fitch Ratings. “The pace of deterioration is coming quicker than what was previously disclosed.”
The pain has been more acute for bondholders, with the big losses hitting portfolio managers who stocked up on high-yield “junk” oil and gas company debt. In February, bond funds lifted cash levels to their highest since 2001, to prepare for investor withdrawals.
Since crude prices began to fall in the summer of 2014, investors in oil and gas companies have lost more than $150bn in the value of their bonds, and more than $2tn in the value of their equities, according to FT calculations.
Falling oil prices have hit other markets as risk appetite declines, says Hyun Song Shin, chief economist at the BIS. “When the credit cycle turns, you have a combination of higher volatility and tighter credit conditions,” he says. “It’s not the losses but the possibility of loss, and financial institutions pre-
emptively cutting their exposure.”
Debt raises the risk of instability by amplifying the downturn’s effect. When prices are low, producers should cut output rather than selling their reserves too cheaply, and that should stabilise markets. But when producers have debts to pay, they do not have that luxury: they need cash to cover interest and repayments. So some producers actually raise output as prices fall.
That perverse dynamic has been in effect around the world. Many analysts expected US shale oil production to fall rapidly if prices went below $70, but the companies slashed costs while raising productivity, so total US output is declining only gently. Russia’s oil production hit a post-Soviet record in January. Saudi Arabia also hit record output last year.
The decline in the industry’s cash flows has prompted huge cuts in investment, with about $380bn worth of projects delayed or cancelled according to Wood Mackenzie, the consultancy. Sooner or later production will fall and the market will come back into balance.
But a long period of volatility in oil prices may persist even after the oversupply is worked off. The decision by Saudi Arabia, Opec’s de facto leader, not to cut its output amid surging US oil production means that prices are being set by market forces, not political decisions.
Daniel Yergin, vice-chairman of IHS, the research group, says shale has made the US “the inadvertent swing producer” in world oil markets. Shale wells are much faster to drill and complete than large developments such as offshore oilfields. “How production goes down and up is determined not by an oil minister, but by thousands of decision makers across the economy,” he says.
The decisions of those thousands of entrepreneurs and investors are in turn shaped by factors including interest rates and the availability of credit. That means the most important decisions for future oil supply could be made, not at Opec in Vienna, but at the Federal Reserve in Washington and the People’s Bank of China in Beijing. As BP’s Mr Dale puts it: “Oil gets caught up in the credit cycle in a way it hasn’t been before.”
Falling production costs mean that if oil rises much above $50, drilling shale wells in the US will start to look attractive again. New wells can break even in all the main shale regions with prices from about $40 to the low $50s, according to Rystad Energy, a consultancy.
What has yet to be tested is how keen banks and bond investors will be to finance that drilling. Mr Dale is one of many in the industry who suspects they will be cautious. “Balance sheets are going to be weak. Companies are going to be starved of credit,” he says. “Shale businesses tend to be small, highly leveraged and highly dependent on raising capital. If risky lending becomes more expensive, it’s almost inevitable that there will be less investment.”
Mr Yergin agrees. “Company directors and bankers will not forget that prices can go down as well as up,” he says. “So we’re not going to see the same 100-miles-per-hour development that we saw when oil was at $100.”
While investment has slumped in the oil industry, in renewable energy it has hit record highs, helped by widespread government support. The commitments on climate change made in Paris in December promise tightening curbs on fossil fuel demand, creating additional risks in oil and gas investment.
At Machinery Auctioneers, Mr Dickerson has been stocking up on cut-price oilfield equipment. He bought four mobile sand containers used in fracking, with list prices of up to $275,000, for $17,000 apiece. When the industry recovers, he expects to sell them for up to $100,000 each. But before that recovery comes there are likely to be plenty more bargains on his lots.