¿Se ha terminado la era de la inflación?

El motor de la inflación, desde 1973, ha sido el precio del petróleo:

1º Por cortes en el suministro: 1973 porque los países de la OPEP decidieron no exportar más petróleo a los países que habían apoyado a Israel durante la guerra de Yom Kipur. 1979 por la revolución iraní y de la guerra Irán-Irak. 1990 por la guerra del Golfo.

2º Por aumento de la demanda de los países emergentes, especialmente China en 2008 y 2011.

Pero el Fracking ha logrado entre el 2013 y el 2015, bajar los costes de producción de más de 80 dólares el barril, a entre 40 y 45 dólares el barril. Y su capacidad de producción, ha demostrado tener una rápida adaptación a la evolución del precio. Por debajo de los 40 dólares la producción se reduce, en los 50 se mantiene estable y, por encima del los 60 se incrementa (1).

Lo que puede suponer que el precio del petróleo se estabilice entre los 40 y los 60 dólares. A no ser que los avances tecnológicos, como la digitalización (2), terminen fijando un precio más bajo.

Por lo que Fracking se puede terminar convirtiendo en un estabilizador, del precio del petróleo.

El otro motor de la inflación es el pleno empleo, pero la globalización, las nuevas tecnologías, la robótica y la inmigración, pueden actuar como un freno a la inflación proveniente del factor trabajo. A no ser que se haga la tonterías de poner frenos a las importaciones de productos, servicios y trabajadores y, las nuevas tecnologías y la robótica.

Pero en cualquiera de los casos, puede que nos encontremos en una era, con bajas tensiones inflacionarias. Lo que puede permitir una subida de los tipos de interés más lenta y que no tengan que subir tanto como en ocasiones anteriores. Aunque esto no quiere decir que no tengamos más crisis financieras, porque la bajada de los tipos de interés ha sido compensada, con un incremento brutal del endeudamiento.

Mar 10th 2016

NO ONE can deny that America’s shale-oil industry is having a hard time. In recent weeks it has suffered the indictment and subsequent death in a car crash of one of its pioneers, Aubrey McClendon; a shellacking from Hillary Clinton, who could become America’s next president; and a warning from Ali al-Naimi, Saudi Arabia’s oil minister, to cut costs, borrow money or face liquidation.

The data illustrate the extent of its woes. The American government’s Energy Information Administration (EIA) says oil production in December, of 9.3m barrels a day (m b/d), was lower than a year earlier for the first time since early 2011 (see chart 1), weighed down by Texas and North Dakota, the heartlands of hydraulic fracturing (fracking). The EIA said on March 8th that it expects American crude production to fall to 8m b/d before it bottoms out in the latter part of next year.

Against that bleak backdrop, the mere hint this week that American oil prices were rebounding towards $40 a barrel, up from a low of less than $30 a barrel a month ago, must have felt like a get-out-of-jail-free card. With a chutzpah typical of the industry, some shale executives see $40 oil as the threshold above which they can resume drilling and make money again—even if America is still awash with record amounts of crude in storage. If they are right about that, it could change the entire dynamics of the oil market, quickly smoothing any upward or downward spike in prices. But it is not at all clear that they are.

In theory, it is not hard for the frackers to increase production rapidly, once it becomes economical. Rig and drilling costs have fallen so fast that some wells could make money with prices around $40-45 a barrel, according to Rystad Energy, a consulting firm (see chart 2). Firms have laid off many workers, but with well-paid jobs hard to find elsewhere, it could be relatively easy to attract them back.

In preparation for higher oil prices, producers from the Bakken field in North Dakota to the Permian and Eagle Ford in Texas have reported that they have hundreds of “drilled but uncompleted” ( DUC) wells. DUCs should be anathema to a self-respecting shaleman; they sink cash into the ground in the form of wells, but defer the all-important fracking that breaks open the shale rock and produces the oil. They could be a quick way to resume production, however. In late February Continental Resources and Whiting Petroleum, two big operators in the Bakken, said that above $40 a barrel they may begin fracking their rising inventory of DUCs.

For most of the industry, however, the problem is not finding oil but finding cash. “No one is sitting on any excess capital,” says Ron Hulme of Parallel Resource Partners, an energy-focused private-equity fund. For years the industry borrowed heavily to finance its expansion, because it was failing to generate enough cash to cover investment in new wells. The supply of credit, whether from banks or the high-yield debt markets, has either dried up or is much more expensive than it was.

Capital expenditure has fallen as a result, but not by enough to balance the books. In the fourth quarter of last year, American and Canadian oil firms spent $20 billion, while generating only $13 billion in cashflow, according to Bloomberg, an information provider.

Only the strongest firms can make up the shortfall by raising capital via the equity markets. (Even they may find this harder, as investors realise that shale companies are less profitable than they once seemed.) The weaker firms are unwilling to sell assets to raise cash because the proceeds would go directly to their creditors. “You’d have to prise those assets from their dying hands,” says Mr Hulme. He notes that even firms that are technically insolvent may have enough liquidity to keep them from such potential fire sales.

Not all of them, though. On March 8th Goodrich Petroleum, a shale oil-and-gas company, said it would postpone paying interest on its debt, as it puts pressure on creditors to exchange debt for equity in order to avoid a default. Three other oil firms, Chaparral Energy, Energy XXI and SandRidge Energy, have also recently missed debt payments. Brian Gibbons of CreditSights, a debt-research firm, says 26 oil-related bond issuers either filed for Chapter 11 bankruptcy or had distressed-debt exchanges last year. He expects the number to rise to 73 by the end of 2017. Those firms still saddled with revolving bank loans are also bracing for the next twice-yearly reassessment of borrowing limits, due next month. These depend on valuations of shale firms’ reserves, and could lead to further strains on cashflow.

To provide a sufficient margin of comfort, prices may have to rally a lot higher than $40 a barrel to lure capital back in. Bobby Tudor of Tudor, Pickering, Holt, an energy-focused investment bank, believes that at $40 a barrel production will continue to decline, at $50 it would flatten out, and only at $60 would it increase. “Drilling wells at today’s commodity prices is still destructive of capital,” he argues. One further wrinkle: as oil prices increase, so can costs. Those, then, who hope that nimble shale producers will be able to move the global oil price up and down just by turning the taps on and off may be disappointed. Their financial backers will be the ones really calling the shots.

Print edition | Business Apr 6th 2017

IT SOUNDS like a spectacular feat of engineering. Employees of Royal Dutch Shell located in Calgary, Canada, recently drilled a well 6,200 miles (10,000km) away in Vaca Muerta, Argentina. In fact, the engineers of the Anglo-Dutch oil major were using computers to perform what they call “virtual drilling”, based on their knowledge of Fox Creek, a shale bed in Alberta, which has similar geological features to Argentina’s biggest shale deposit. They used real-time data sent from a rig in Vaca Muerta to design the well and control the speed and pressure of the drilling. On their second try, they completed the well for $5.4m, down from $15m a few years ago. “It’s the cheapest well we’ve drilled in Argentina,” says Ben van Beurden, Shell’s chief executive.

Shell is not alone in deploying computer wizards alongside geologists in an attempt to lower costs in an era of moderate oil prices. The industry as a whole is waking up to the fact that digitisation and automation have transformed other industries, such as commerce and manufacturing, and that they have been left behind. Technology firms and consultancies are knocking on their doors peddling alluring concepts like the “digital oil rig” and the “oilfield of the future”. Some argue that the embrace of digital technologies could be the next big thing after the shale revolution that started to transform oil and gas production in America a decade ago. But this is an industry that embraces new technologies only in fits and starts.

Once, Big Oil was at the forefront of digitisation, pioneering the use of 3-D seismic data and supercomputers to help find resources. But priorities changed, especially during the past decade when oil prices rose above $100 a barrel and the primary goal was to find more of it, whatever the cost. Whizzy new technology took second place. Ulrich Spiesshofer, chief executive of ABB, a Swedish-Swiss automation-technology company, says the oil industry puts to use in exploration activities barely 5% of the seismic data it has collected. During production of oil, less than 1% of data from an oil rig reaches the people making decisions, reckons McKinsey, a consultancy.

It is the process of extracting oil and gas that is considered most ripe for digitisation and automation. Drilling often takes place miles below the surface in rock formations where drill bits and pipes can be broken or snagged, which halts activity for long periods. Baker Hughes, an oil-services firm, has recently developed what it calls the first automated drill bit, capable of self-adjusting depending on the nature of the rock. McKinsey says undersea robots are also being deployed to fix problems.

Above the surface, efforts are under way to reduce the amount of people and plant on oil rigs, helping improve safety in a dangerous industry. James Aday, a veteran oil driller now at Wood Mackenzie, a consultancy, says that on the drilling platform itself, automation is not new. Others say that more rigs are being controlled semi-remotely; in the Gulf of Mexico, engineers in Houston use real-time data from oil rigs to make decisions, reducing the cost of shuttling them by helicopter to rigs. “The aim is to bring the data to the expert, not the expert to the data,” says Peter Zornio of Emerson, an automation firm. “There’s a huge incentive to get the people and the choppers off the platform.”

Wider use of data, sensors and automation will produce new challenges for the industry. It will have to learn about cyber-security—oil rigs are critical infrastructure—and invest in ways to prevent theft of data. But digitisation may also attract millennials to replace an ageing workforce, where mass retirement is a looming threat.

As to whether the workforce could shrink across the industry in the digital age, ultimately geologists and engineers believe technology will not put them out of a job, because producing oil is art as well as science. Nor will tech startups be likely to overcome the barriers to entry—such as high capital requirements—that protect incumbents. But they add to a sense, born out of the shale revolution, that innovation will make oil and gas more accessible and that the days when oil was considered a scarce resource are long gone.