Price Differentials

Big changes are coming to the new epicenter of the global LNG market: Texas and Louisiana. On top of the existing 12.5 Bcf/d of LNG export capacity in the two states, another 11+ Bcf/d of additional capacity is planned by 2028. The good news is that the two major supply basins that will feed this LNG demand — the Permian and the Haynesville — will be growing, but unfortunately not quite as fast as LNG exports beyond 2024. And there’s another complication, namely that the two basins are hundreds of miles from the coastal LNG terminals, meaning that we’ll need to see lots of incremental pipeline capacity developed to move gas to the water. 

Big changes are coming to the new epicenter of the global LNG market: Texas and Louisiana. On top of the existing 12.5 Bcf/d of LNG export capacity in the two states, another 11+ Bcf/d of additional capacity is planned by 2028. The good news is that the two major supply basins that will feed this LNG demand — the Permian and the Haynesville — will be growing, but unfortunately not quite as fast as LNG exports beyond 2024. And there’s another complication, namely that the two basins are hundreds of miles from the coastal LNG terminals, meaning that we’ll need to see lots of incremental pipeline capacity developed to move gas to the water. 

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. 

Whew. We made it! 2020 is finally in the rear-view mirror. And with the New Year, it’s time for the annual Top 10 Energy Prognostications blog, our long-standing RBN tradition where we lay out the most important developments we see for the year ahead. Unlike many forecasters, we also look back to see how we did with our predictions the previous year. That’s right! We actually check our work. Usually we roll our look back and prognostications for the upcoming year into a single blog. But after the mayhem of 2020, and considering how that upheaval has changed the landscape for 2021, this time around we are splitting our prognostications into two pieces. Monday’s blog will look into the RBN crystal ball one more time to see what 2021 has in store for energy markets. But today we look back. Back to what we posted on January 2, 2020.

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.

The collapse in WTI prices in March has been a crushing blow to the Permian, the Bakken and other U.S. shale plays that produce light, sweet crude oil. But as bad as sub-$25/bbl WTI prices are — especially for producers whose balance-of-2020 volumes aren’t at least partly hedged at higher prices — consider the record-low, $5/bbl prices facing oil sands producers up north in Alberta. Western Canadian Select, the energy-rich region’s benchmark heavy-crude blend, fell below $10/bbl more than a week ago, and on Tuesday WCS closed at $5.08/bbl. Producers, who already had been dealing with major takeaway constraints, are ratcheting back their output and planned 2020 capex, and slashing the volumes they send out via rail in tank cars. Today, we begin a short blog series on the latest round of bad news hitting Western Canada’s oil patch.

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.

Right now, pipeline capacity out of the Permian is constrained, and consequently some producers have cut back on well completions, more gas is getting flared, and ethane recovery is being driven more by bottlenecks than by gas plant economics.  But even with these issues, there are still 487 rigs drilling for oil in the basin (according to Baker Hughes), and all will come along with sizable quantities of natural gas.    Not only does this production need to be moved out of the Permian, the volumes need to find a home — either in the domestic market or overseas. These were all issues that were considered by our speakers, panelists and RBN analysts last month at PermiCon, our industry conference designed to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence.  In today’s blog, we continue our review of some of the key points discussed during the conference proceedings.

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.