RBN Energy

The combination of rising condensate demand as new splitter capacity came online and falling conde supply resulted in just what you’d expect — higher conde prices. Worse yet for the companies that made throughput commitments for those new splitters, the once-favorable price differentials between conde and light-crude benchmarks West Texas Intermediate (WTI) and Louisiana Light Sweet (LLS) have been turned on their heads, and a number of splitters are operating at far less than capacity. Today, we continue our look at the roller-coaster world of conde, this time focusing on conde prices and differentials, and on the forces that may change the conde market once again.

The sharp decline in U.S. condensate production since early 2015 and the end to the ban on U.S. crude oil exports a few months later were a one-two punch for the companies that made throughput commitments to condensate splitters and made other conde-related infrastructure investments. In what seemed like a flash, conde supply plummeted and the steep price discount to WTI and other light crude that made conde so attractive for splitting and exporting was gone. Holders of splitter capacity were paying top-dollar for what conde they could corral, and operators were forced to run their brand-new facilities at far less than capacity. And, when the general ban on crude exports was lifted in December 2015, the special status that conde had enjoyed since exports of lightly processed conde were permitted in June 2014 was a thing of the past. Today, we continue our review of a conde world in upheaval, this time with a focus on splitters and exports.

Back in 2015, U.S. production of superlight crude oil and condensate had been on the rise for five years, driven primarily by boom times in the Eagle Ford shale play in South Texas. Condensate was selling for several bucks-a-barrel less than light-crude benchmark West Texas Intermediate (WTI), the U.S. government had recently approved the export of minimally processed condensate, and new condensate splitters were being built to allow refineries to use more high-API-gravity liquids. Fast forward to now, though, and production of superlight crude and conde is off by one-third ­­— the lighter the material, the steeper the decline — a barrel of conde is selling for several dollars more than WTI and a lot of those new splitters are running at far less than full capacity. As for exports of neat conde, they’ve dropped to almost zero, and whatever superlight crude and conde that is being exported goes out as part of blended crude. But things could be about to change again, possibly in a big way. Today, we begin a new blog series on the chaotic U.S. conde and superlight crude market.

The crude oil-carrying Dakota Access Pipeline (DAPL) has been up and running for almost six months now, creating new market dynamics in the Bakken. But these changes haven’t garnered all that much attention — they’ve been overshadowed by talk of Permian production growth, Gulf Coast pricing and Cushing pipeline capacity. Now though, with news of super-long three-mile laterals and increasingly positive producer sentiment, the Bakken is once again shifting into the limelight — and the 525-Mb/d DAPL from western North Dakota to Patoka, IL is center-stage. Today, we discuss DAPL’s effects on Bakken crude prices, market access, other takeaway pipelines and crude by rail.

A number of producers in the Permian and other shale plays are rethinking their strategies for using, procuring and delivering frac sand ­­— all with the aim of minimizing sand costs, which account for a sizable and increasing share of total drilling and completion expenses. The focus on frac sand stems from evolving completion strategies that are pumping ever-larger volumes of sand into horizontal wells resulting in sharply higher hydrocarbon production. That has caused sand demand — and prices — to soar, and prompted the rapid development of new sand mines close to shale-production hot spots like West Texas, in part to reduce sand transportation costs. Today, we continue our blog series on recent developments on the frac sand front.

Wide swings in the value of Permian crude oil in Midland, TX, the storage and distribution hub in Cushing, OK, and Gulf Coast points like Houston in recent months have only reinforced the importance of destination flexibility. The ability of Permian producers and shippers to access multiple takeaway pipelines and, with that, the market that will give them the highest possible price for their product, is being enhanced by the addition of new intra-basin shuttle pipelines, gathering systems and hybrid gather-and-shuttle networks. These new pipes are designed to help connect new wellheads across the Permian’s Midland and Delaware basins with two, three or even more takeaway pipelines, adding new robustness to the region’s infrastructure and enabling crude to flow to where it is most valued at any given time. Today, we discuss highlights from our new Drill Down Report on Permian crude oil shuttle pipelines and gathering systems.

In the past year, there have been major changes in the frac sand sector. Exploration and production companies in the Permian and other growing areas have significantly ramped up the volume of sand they use in well completions, catching high-quality sand suppliers in the Upper Midwest off-guard and spurring sharply higher frac sand prices due to the tight supply. At the same time, development of regional sand resources has taken off in the Permian — with close to 20 mines announced with upwards of 60 million tons/year of nameplate capacity possible — and, to a lesser extent, in the SCOOP/STACK, Haynesville and the Eagle Ford. That new capacity should begin easing sand-supply shortfalls next year, reducing sand delivered costs and potentially threatening the dominance of traditional Northern White sand. And more changes are ahead in 2018. Today, we begin a new blog series on fundamental shifts in the all-important frac sand market.