Cushing

There’s a lot going on in North American crude oil markets these days. Exports are running strong. Midland WTI is now deliverable into Brent (but only if it meets specs). Pipelines from the Permian to Corpus Christi are maxed out, pushing incremental production to Houston. The price differential between WTI at Midland and Houston is nearing zero. And the value of heavy Western Canadian Select (WCS) delivered to the U.S. continues to bounce all over the place. Are these unrelated, random events in the quirky U.S. physical crude market, or are they logical developments linked by the economics of refinery preferences, quality shifts, export demand, and logistics? As you might expect, we think it’s the latter. Believe it or not, crude markets sometimes do behave rationally — and, from time to time, even predictably. That’s what we explore in today’s RBN blog.

Crude oil exports hit 5.6 MMb/d last week, the second-highest level in EIA stats ever. Exports in the first six months of the year have averaged 4.1 MMb/d, 28% — or nearly 1 MMb/d — higher than the same period in 2022. And with Midland WTI crude now deliverable into global benchmark Brent, even more exports are on the way. Which makes it ever more important to understand how physical spot crude oil is priced at Gulf Coast export terminals.  After all, exporters only move crude off the dock when they can make money doing so — well, at least most of the time. And that depends on what it costs to get a given crude grade to the dock, what it’s worth when it gets there, the cost of shipping to overseas destinations, and the price realized when the cargo lands there. To shed more light on those export economics, in today’s RBN blog, we continue our exploration of crude oil pricing in the markets for physical U.S. and Canadian crudes. 

Trading in the highly integrated US/Canadian crude oil market is undergoing a profound transformation, driven mostly by the pull of exports off the Gulf Coast. But the shifts in flows, values and even the trade structures being used today are not well understood outside a small cadre of professional traders and marketers. Consider a few examples: Domestic sweet oil traded at Cushing on NYMEX is not West Texas Intermediate — WTI at Cushing has averaged a hefty $1.80/bbl over NYMEX for the past year. Most spot Houston and Midland crudes trade as buy-sell swaps. WTI in Houston trades at a discount to Corpus Christi and sweet crudes in Louisiana. Crude in Wyoming trades at a premium to Cushing. And the Gulf Coast is the highest-value market for Canadian heavy crude. This is not your father’s (or mother’s) oil trading game. Our mission in this blog series is to pull back the curtain on physical crude trading in North America, explain how it works, what sets the price, and who is doing the deals. 

The world is in desperate need of more crude oil right now and anybody with barrels is scouring every nook and cranny for any additional volume that can be brought to market. Some of that may come from increased production, but the oil patch is a long-cycle industry, just coming off one of the most severe bust periods ever, and it will take time to get all the various national oil companies, majors, and independents rowing in the same direction again. For now, part of the answer will be to drain what we can from storage — after all, a major purpose of storing crude inventories is to serve as a shock absorber for short-term market disruptions. To that end, the U.S. is coordinating with other nations to release strategic reserve volumes to help stymie the global impact of avoiding Russian commodities. Outside of reserves held for strategic purposes though, commercial inventories have already been dwindling as escalating global crude prices have been signaling the market to sell as much as possible. Stored volumes at Cushing — the U.S.’s largest commercial tank farm and home to the pricing benchmark WTI — have been freefalling for months, which raises the question, how much more (if any) can come out of Cushing? In today’s RBN blog, we update one of our Greatest Hits blogs to calculate how much crude oil is actually available at Cushing.

You would expect the start-up of Enbridge’s Line 3 Replacement project early this fall to have eased the constraints on crude oil pipelines from Western Canada to the U.S. — and it did. You’d also expect that L3R coming online would narrow the price spread between Western Canadian Select and West Texas intermediate — but it didn’t. The latest widening of the WCS-WTI spread, one of many in recent years, is another reminder that oil price differentials can be affected by many factors other than pipeline capacity availability. In today’s RBN blog, we discuss the host of issues that affect this all-important Canadian oil price metric.

Well, it’s been 365 days since the unthinkable happened: the price of WTI at Cushing went negative last April 20, and by a solid $37.63 a barrel at that. The insanity didn’t end there, though. The pandemic that many thought would be behind us in a season or two at most had a second wave, then a third and, some say, a fourth. U.S. refinery demand for crude oil, which plummeted by more than 3 MMb/d last spring, still has only recouped only half that loss. E&Ps, who shut in thousands of wells when oil demand and prices tanked, still are only producing 11 MMb/d — 2 MMb/d less than they were pre-COVID. LNG exports took a big hit too, another victim of demand destruction. As if all that weren’t enough, a couple of months ago, just as new vaccines were providing hope that everything would soon be returning to normal, the Deep Freeze put the Texas economy on ice and slowed production and refining once again. Strange times indeed. But we’re learning from it all, right? Today is the one-year anniversary of oil price Armageddon, so we take a look back at 12 months of market madness that no one could have predicted.