For those that believe the shale oil phenomena put to rest, forever, the threat of peak world oil production rates and America is now home free with regard to its hydrocarbon future, read this from the Financial Times. Its painful, I know, but its reality...
How much has the US oil industry been inflated, crushed and generally distorted by the Federal Reserve’s monetary force-feeding over the past nine years? According to my probing along the stages of production and trading, the answer is “a lot”.
Yes, there have been dramatic developments in hydrocarbon production technology, but those looked even better through the distorted lens of quantitative easing. Oil and gas pricing have now stabilized, in the sense of finding a finance-friendly range somewhere north of $50 per barrel. There have been lay-offs and bankruptcies, but fewer than in the oil bust of the 1980s. Manhattan and Oklahoma City were treated relatively well by quantitative easing. In many ways it is easier for cheap money to find its way into the energy business than into the rest of the US economy, thanks to the breadth, depth and long-dated terms offered by the futures markets. As Jim Bianco, president of Bianco Research, the analytics company in Chicago, points out: “There are active oil futures contracts all the way out to December of 2025, while, say, copper futures are only liquid out for a couple of years. So a private equity or hedge fund investor figured that if he got [an energy investment] wrong, he could easily hedge out his exposure.” Also, the operating people in the US oil and gas business have been very knowledgeable about public equity and debt markets for a long time. After 2008, when the banking system was reluctant to take risk, they knew how to turn around and sell a story such as “shale” to public investors. Since interest rates were artificially low, investors were willing to discount the projected revenues from imaginatively estimated oil and gas reserves at unrealistic levels.
Even after prices peaked in 2011, exploration and production operators could raise the money to fund aggressive capital spending. A significant part of the excess production was put into storage, where it was cheaply financed by naïve city people who did not get the joke. Crude oil storage capacity at Cushing, Oklahoma, the centre of West Texas Intermediate oil deliveries, increased from 45m barrels in 2011 to 76m today. “This wasn’t some sort of smart play,” says one commodities investor. “It was a giant mistake.” Sign up to the Energy Source email, weekly Review the week’s must-read energy news, comment and analysis. weekly Just how big a mistake was not immediately evident, since official statistics did not capture how much oil was being crammed under the mattress. Todd Dauphinais, a principal at Clavis Capital, a Dallas private equity firm, led a 2016 buyout of Alliance Tank Service, an oil storage-tank manufacturer. The Alliance Tank deal was not premised on the direction of oil prices, but on the industry’s need to replace old facilities. Good thing, too. “Even as prices crashed, people still had to pump it out of the ground. It got stuffed in every available storage vessel, such as rail cars or oil barges, which really don’t make a lot of sense,” Mr Dauphinais recalls. “A lot of that would not have been reported at the time, and we figured that was all over and above what the [official numbers] said. “When we bought Alliance, Cushing was reported to be at 87 per cent of capacity, but since the 13 per cent was really operating margin, it was really completely full.”
In a normal world, some of the oil producers who signed long-term drilling contracts in the good years would have gone bankrupt from 2011 on, but they kept getting refinanced. As Tom Ward, a longtime exploration and production person from Oklahoma City, says: “Quantitative easing really was driving the whole energy market after 2008. The producers had three- to five-year contracts for rigs left from 2014 and before, and they had to pay whether they drilled or not.” So they continued to drill until this past year.
Not all the wells were completed, as in fracked, cased and connected to the gathering systems. That means that oil and gas were not only stored in above-ground tanks, but in drilled but uncompleted wells that are only gradually being finished and hooked up to the markets. Over the past year, equity and bond investors have forced onshore E&P companies to be more disciplined about their capital spending. That does not mean spending only their internally generated cash flow, of course. That would be like asking a prima ballerina to live within her salary. But the onshore industry is in much better shape than it was.
The US offshore industry in the Gulf of Mexico, on the other hand, has not really recovered. William New, president of New Industries in Morgan City, Louisiana, which makes pressure vessels, piping and the like for offshore projects, is still waiting for the good times to roll again. “The problem is even when [the customers] go bankrupt, the equipment doesn’t go away. In the 1980s it took 10 years to come back, and we are only in the third year,” he says. So there will be fewer offshore US mega-wells to upset the balance. With inventories having fallen even more sharply than the reported numbers, the oil and gas industry is not badly prepared for rising interest rates.
So, if your thinking "peak oil," rather, the ability for the world to maintain oil production rates equal to consumption rates, is a joke, best think again.
Who's going to be short on hydrocarbons in the future and very long on debt and debt related deflationary problems?
Our kids, that's who !