Price Differentials

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. 

The crash in global crude oil markets has meant low prices for all producers, but no place more so than in Alberta’s oil sands. Transportation, blending and quality differentials mean that benchmark Western Canadian Select (WCS) is priced at a significant discount to light, sweet West Texas Intermediate. With WTI prices seemingly stuck below $30/bbl, the absolute price of WCS last week tumbled to all-time lows below $5/bbl. If they persist, will WCS prices south of $10/bbl generate wide-scale production shut-ins in the oil sands? Today, we continue our series on the challenges facing Alberta’s oil sands.

December 2019 U.S. crude oil production soared 1.1 MMb/d above this time last year to 12.8 MMb/d. It’s a similar story for natural gas, with Lower-48 production climbing to 95 Bcf/d, up 6 Bcf/d over the year. That’s a little off the breakneck growth rate of 2018, but still quite healthy, even in the context of Shale Era increases. And it all happened in the face of continued infrastructure constraints, crude prices that fell from the mid-$60s/bbl in April to average $55/bbl from May through October, and gas prices that in several months were crushed to the lowest level in 20 years. It’s all too much supply to be absorbed by the U.S. domestic market. And that means more pipes to get the supply to the Gulf Coast and more export facilities to get the volumes on the water. What has all this meant for the market’s response to these developments? Well, at RBN we have a way to track that. We scrupulously monitor the website “hit rate” of the RBN blogs fired off to about 28,000 people each day and, at the end of each year, we look back to see which topics generated the most interest from you, our readers. That hit rate reveals a lot about major market trends. So, once again, we look into the rearview mirror to check out the top blogs of the year based on the number of rbnenergy.com website hits.

Permian oil and gas production may have slammed up against capacity constraints, but that does not mean production growth has ground to a halt. Far from it. In the past 10 weeks, Permian gas production is up another 8% — a gain of almost 700 MMcf/d. Crude production now tops 3.5 MMb/d, with incremental barrels finding their way to market via truck, rail and new pipeline capacity — soon including Plains All American’s new Sunrise project, which will move more Permian crude toward the hub in Cushing, OK. Record-setting volumes of NGLs are streaming their way out of the Permian to Mont Belvieu. This market is moving so fast that if you blink, you’ll miss something important. So to get caught up with all things Permian, last week RBN hosted PermiCon, an industry conference designed to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence. We think PermiCon accomplished that goal, and in today’s blog, we summarize a few of the key points discussed during the conference proceedings.

The recent collapse in the price of Western Canadian Select (WCS) versus West Texas Intermediate (WTI) and the 12-day shutdown of the Keystone Pipeline in November 2017 put the spotlight on a major issue: Alberta production is rising, pipeline takeaway capacity out of the province has not kept pace, and pipes are running so full that some owners have been forced to apportion access to them. Storage and crude-by-rail shipments have served as a cushion of sorts, absorbing shocks like the Keystone outage and the apportionments, but with more production gains expected in 2018-19, that cushion seems uncomfortably thin and unforgiving. With all this going on, we decided that it’s time for a deep-dive look at Western Canadian production, takeaway options and WCS prices — the whole kit and caboodle. Today, we begin a new series on Canadian crude and bitumen production, the infrastructure in place (and being planned) to deal with it, and the effects of takeaway constraints on pricing.

Two months ago, U.S. crude oil exports skyrocketed, and they have averaged 1.6 MMb/d since mid-September, driven by a Brent-WTI differential above $6/bbl — higher than it has been in over two years. At one point, the steep differential and surging exports were blamed on Hurricane Harvey, then on renewed OPEC discipline and a political risk premium associated with a shakeup in the Saudi hierarchy. But the reality is that these factors are only small pieces of the equation, with pipeline transportation bottlenecks from Cushing and the Permian down to the Gulf Coast being much more important factors in the widening Brent-WTI price spread. Today, we begin a blog series examining how these pipeline capacity constraints triggered the expanded price differential, and how the differential then enabled high crude oil export volumes.