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The FreightWaves oil report: sorting out what the Venezuela sanctions mean for the market

A weekly look at what occurred in the oil markets of the U.S. and the world this past week.

The week just ended might be referred to as “Venezuela week.” With the news that the U.S. was sanctioning PDVSA, the Venezuelan state oil company – at one time considered the most well-run state oil company in the world, staffed by talented people but now in ruins – the market began to assess just what that would mean for supplies out of that country and how it might affect the price of oil.

Here are a few things to remember about this standoff and its possible impact on  supply and demand.

  • The sanctions are not a ban on U.S. imports of crude from Venezuela. But they are considered onerous enough to be a de facto ban. Most market participants are expecting that Venezuelan crude exports to the U.S. – which have been averaging 500,000 barrels per day for the last few months – will probably cease, as well as U.S. exports of products to Venezuela. That latter category includes diluent, a loosely defined category of very light oils that are needed to get the “heavy” Venezuelan crude to “move” after being blended in. (The U.S. exports a huge amount of diluent to Canada for the same reason; oil from the Alberta oil sands is extremely heavy as is some oil from conventional sources.)

  • What happens then? In a perfect economic world, supply lines readjust, Venezuelan oil goes elsewhere, the U.S. exports less crude or imports more from somewhere else and the  market is rebalanced. But it’s not a perfect economic world. In particular, Venezuelan crude is sour – high in sulfur – and extremely heavy; that’s why it needs the diluent. U.S. refiners are equipped to process it; many refiners in other parts of the world aren’t. For years, U.S. refiners reconfigured their engineering on the assumption that they’d be taking in more heavy oil from Venezuela, Mexico and Canada. But the shale revolution, with its flows of light crude, threw a wrench into those plans. The potential impact in the U.S. then is that some refiners who banked on heavy crude, like Valero, are going to have to bid more heavily for heavy crudes to replace the Venezuelan supplies; Canada and Mexico should be the beneficiaries and market reports are increasingly referring to the “sour shortage.” The potential negative impact to Venezuela, on top of all its other problems, is that it might need to accept a lower price than from its customers in the U.S. to sell its oil in to refiners who aren’t set up to get the full value out of such a heavy crude. That’s compounded by the fact that it needs to find diluent somewhere else.

  • Also complicating the Venezuela situation are reports that the U.S. government might seek to release crude oil from the Strategic Petroleum Reserve (SPR). It is a complicating factor because theoretically, there is no loss of supply to global markets. The last time the SPR released oil outright to deal with a shortfall in supply – as opoposed to lending it out during a less-serious disruption, to be paid back with crude as interest – was when the Libyan revolution erupted in 2011. But if Venezuela can find a way to keep pumping oil despite the sanctions and the marketing problems it brings, the SPR will be releasing oil into a market that hasn’t suffered a shortfall. In an oil market that is well-supplied, that could be a strongly bearish factor and offset some of the cuts that OPEC has made since December.

In other developments this week:

– The parade of monthly reports of what OPEC did in the prior month has begun. The first out of the gate was Reuters, which estimated that OPEC produced 30.98 million barrels per day (b/d) in January. This would be down 890,000 from Reuters’ estimate in December. Comparisons of month-to-month final numbers are going to be a little tricky this month because these estimates, from places like Bloomberg and S&P Global, will be dropping the roughly 600,000 b/d that Qatar produces from their estimates now that it has left the organization. Additionally, there was a significant difference in estimating the size of the cuts made in December among the forecasters. But the important thing to know is that if OPEC cut 890,000 b/d in January, Reuters’ estimates are that OPEC output in January will be 569,000 b/d less than the level it produced in October 2018, which was the baseline for the group’s pledge to reduce output by 800,000 b/d. A day after the Reuters report, Bloomberg estimated a 930,000 b/d cut by OPEC in January. There are still three significant estimates to come in – S&P Global Platts, OPEC itself and the International Energy Agency. But based on the two reports out there already, OPEC is getting to its goals quicker than most people believed possible.

– A small impact to the supply/demand balance will be coming out of Alberta. Late last year, in an unprecedented move, Alberta Premier Rachel Notley ordered production cuts of 325,000 b/d to help support not just the overall price but the price of Alberta crude relative to benchmarks like West Texas Intermediate (WTI). That differential had slid to as much as $40/b. It has since rebounded to as little as $10/b less than WTI. Notley said this week that she would allow increases of 75,000 b/d in February and March.

– U.S. crude refining capacity is getting a big boost with the announcement by ExxonMobil that it will be adding 250,000 b/d in crude distillation capacity to its Beaumont, Texas refinery. That will bring total capacity there to about 615,000 b/d, making it the largest refinery in the country. In the trucking world, the only question these days is will that refinery help make more diesel fuel, to help soften the blow from the existing diesel pool draining increasingly into the marine market to meet the mandates of IMO 2020? Just the addition of crude distillation capacity, the most basic part of the refining process, does little to answer “yes” to that question. But earlier in 2018, ExxonMobil completed a capital project at Beaumont that increased the production of ultra-low sulfur fuels, gasoline and diesel, by approximately 450,000 b/d. Additionally, as noted in the discussion about Venezuela, U.S. Gulf Coast refineries were oriented toward processing the heavy oil out of Venezuela, Canada and Mexico before the shale revolution turned oil markets upside down. Additional capacity in the U.S. Gulf now to process lighter crudes can add capability to producing products that are coming from a lighter-sulfur blendstock, which is the case with the oil coming out of places like the Bakken and the Eagle Ford fields. ExxonMobil’s plans are a win for the consumers of diesel.

John Kingston

John has an almost 40-year career covering commodities, most of the time at S&P Global Platts. He created the Dated Brent benchmark, now the world’s most important crude oil marker. He was Director of Oil, Director of News, the editor in chief of Platts Oilgram News and the “talking head” for Platts on numerous media outlets, including CNBC, Fox Business and Canada’s BNN. He covered metals before joining Platts and then spent a year running Platts’ metals business as well. He was awarded the International Association of Energy Economics Award for Excellence in Written Journalism in 2015. In 2010, he won two Corporate Achievement Awards from McGraw-Hill, an extremely rare accomplishment, one for steering coverage of the BP Deepwater Horizon disaster and the other for the launch of a public affairs television show, Platts Energy Week.