A weekly look at what occurred in the oil markets of the U.S. and the world this past week.
One of the fathers of the peak oil movement – the idea that the world was reaching its peak capacity to produce oil before a long decline would begin – was Matthew Simmons, who headed an oil and gas boutique investment bank named after him. Simmons was controversial, despised in some quarters but absolutely worshiped by the peak oil advocates. When he would show up at the annual meeting of the Association for the Study of Peak Oil and Gas – yes, there is such a thing – it was almost like that moment at a political convention when the nominee first steps to the podium and the crowd goes wild. (I witnessed it several times in person.)
Simmons, who died in 2010, was dismissive until the end of the first signs of the shale revolution. He wrote the book Twilight in the Desert: The Coming Saudi Oil Shock and the World Economy. It was published in 2005. It was a sensation. Geologists who were peak oil backers viewed it as their Bible; peak oil followers who were just simply anti-fossil fuel saw it as an industry leader calling for the world energy paradigm to move to alternatives. Simmons himself was a big backer of ammonium as an energy source.
One of the key themes in the book was that Saudi Arabia’s giant Ghawar field, the world’s largest, was rapidly depleting and that the Saudis had been forced to undertake almost superhuman efforts to keep its production from falling. This past week, when Saudi state-owned oil company Aramco published a prospectus in connection with an upcoming bond offering, Simmons’ theories got a boost.
Bloomberg pored through the report and found that Ghawar’s maximum output was 3.8 million barrels per day (b/d), “well below the more than 5 million b/d that had become conventional wisdom in the market,” the Bloomberg report said. The Bloomberg article dug out an old U.S. Energy Information Administration (EIA) report that listed Ghawar’s capacity as 5.8 million b/d. Simmons, back at the time of the book, said the output was 5 million b/d and the Saudis would have a tough time maintaining that.
The Saudis have maintained their output; according to S&P Global Platts, Saudi oil output hit 11 million b/d in November 2018 before self-imposed production cuts have brought it down to 9.9 million b/d. According to an annual report of oil data put out each year by BP, in 2004 the Saudis produced about 10.5 million b/d. So in one sense, Simmons was right; Ghawar was in decline. But his basic thesis was that the country as a whole would start to decline, a step down the road to “peak oil.” That clearly hasn’t happened.
The revelation this week about Ghawar does confirm that the world’s biggest oil field is in the U.S. – the Permian. The latest numbers from the EIA are that output there is 4.1 million b/d. Ten years ago, it was less than 900,000 b/d.
An ExxonMobil executive this past week said something that truck owners are not going to want to hear.
Luca Volta, in an interview with Seatrade Maritime News, said that the marine industry should not just be looking to a new family of fuel oil products with less than 0.5 percent sulfur known as Very Low Sulfur Fuel Oil (VLSFO) to comply with IMO 2020. Volta, who is marine fuels venture manager at ExxonMobil, said that distillates – which is the broad category of products that includes diesel – also are a way of getting compliant with the sulfur rules of IMO 2020. “Distillates, ranging from 0.5 percent to 0.10 percent, are one of those other means of compliance and our distillates are available at a number of locations around the world as the industry will need both – residual fuels and distillate fuels, both compliant,” Volta was quoted as saying.
This could almost be described as the nightmare scenario for diesel users. VLSFO is produced in part by blending vacuum gasoil (VGO), an intermediate distillate product, to make the compliant fuel oil product. That process therefore produces new distillate demand, competing with producers of finished diesel who would also be looking to process VGO.
The problem comes in the transition, when shipowners are not using VLSFO and instead turn to the products that Volta speaks of. They are known in the industry as marine gasoil (MGO) or marine diesel (MDO) and they are widely used now. The concern is that there will be a surge in demand for MGO and MDO as the transition to IMO 2020 begins on January 1, and that will put pressure on the diesel market. MGO/MDO have the benefit of being known quantities, whereas the new blends of VLSFO do not. Turning to them as compliant fuels does not pose an operational risk for shipowners as they’ve probably used them previously.
Of course, that will also mean less demand for VGO from the new family of VLSFO products that will need time to prove their acceptance with many shipowners. That’s good for distillate supplies. But Volta’s suggestion appears to be the more troublesome for diesel users. Turning to MGO/MDO is essentially a 100 percent distillate solution. VLSFO would have VGO as a blendstock; it isn’t a 100 percent distillate solution. That could be a problem.
So far, the market is not showing any signs of concern even as the industry meets regularly at conferences to discuss IMO 2020. Prices on the CME’s ultra low sulfur diesel (ULSD) contract out in January and February are higher than they are now, but that is a normal curve and to be expected given that the ULSD contract is also essentially a heating oil contract. (It actually used to be a heating oil contract until the two products became more aligned with specification changes mandated by environmental regulations.) So far, it seems, there aren’t a lot of traders willing to make a bet on a price surge as IMO 2020 kicks in.
A price hasn’t hit rock-bottom until it gets to zero, right? Think again. These past two weeks, natural gas at certain locations in the Permian Basin has fallen to as much as a negative $6 per 1,000 cubic feet. (The benchmark price at the Henry Hub, Louisiana delivery point is about $2.65/Mcf). The negative price means that a producer needs to pay somebody a certain amount of money to take the gas away. That lucky individual or company would be somebody who has pipeline capacity.
This shift to negative numbers is happening because natural gas production in the Permian is soaring alongside its oil production (as we noted above, it’s now the world’s biggest field) and there isn’t enough pipeline takeaway capacity to bring the natural gas to market. Oil has that problem too but it solves it by putting oil and natural gas liquids on rail cars to get it to market. So if the price is negative, why even produce it? Because it’s either a byproduct of oil production, or the natural gas liquids (NGLs) that are produced as a byproduct or NGLs are valuable enough to keep the natural gas flowing. There are regulations regarding flaring so it can’t be just burned off easily. The value of the oil or the NGLs means the economics still work.
It’s not “Buddy, can you spare a dime?” It’s “Buddy, can you take this gas off my hands? And here are a few bucks for your trouble.”