CME’s NYMEX light sweet crude oil contract in Cushing, OK, is not West Texas Intermediate — WTI. Instead, it is Domestic Sweet — commonly referred to as DSW — with quality specifications that are broader and generally inferior to Midland-sourced WTI. In fact, pristine Midland WTI delivered to Cushing sells at a reasonably healthy premium to DSW. That difference in specs, and the fact that the quality of DSW is considerably more variable than straight-as-an-arrow Midland WTI, makes most purchasers of exported U.S. crude (and many domestic refiners too) strongly prefer the more quality-consistent Midland WTI grade. For that reason, when Platts set out to allow U.S. light crude to be delivered as Brent, it said that only Midland WTI will qualify. Consequently, a marketer cannot take delivery of a NYMEX-quality barrel at Cushing, pipe it down to the Gulf Coast, and deliver it to a dock for export if the ultimate destination of that barrel is to be reflected in the Brent price assessment. The implication? There are now effectively two U.S. crude oil benchmark grades, each of which is valued differently, priced differently and used by different markets. Is this a big deal for the valuation mechanisms for U.S. crude oils, or just a minor quirk in oil-market nomenclature? We’ll explore that question in today’s RBN blog.
Posts from Taylor Noland
For years, oil and gas companies struggled to win over investors, largely because of the energy sector’s notoriously volatile history — marked by boom-and-bust cycles and sometimes scary levels of indebtedness. You might think the pandemic and the subsequent upheaval in energy markets would only make matters worse, but the chaos actually forced energy companies to get their finances in better order and, in many cases, to either acquire other companies or be acquired themselves. Financial discipline and consolidation provided another benefit: sharply improved credit ratings, which have the knock-on effect of making companies even more attractive. In today’s RBN blog, we discuss the forces behind, and the importance of, the improved credit ratings that resulted from this massive wave of consolidation.
When the calendar flipped from June to July, it did more than just close the book on the first half of 2023, it also allowed some oil pipelines regulated by the Federal Energy Regulatory Commission (FERC) to increase their rates by more than 13%. Yes, you read that correctly. This is the largest increase in the index rate since FERC initiated its current methodology in 1992 and follows last year’s increase of almost 9%. In today’s RBN blog, we look at what’s going on with index rates at FERC and what it means for producers and shippers alike.
With ever-increasing volumes of Permian crude oil being exported and the recent inclusion of WTI Midland in the assessment of Dated Brent prices, the issue of iron content — especially in some Permian-sourced crude — is coming to the fore. This has become such a point of emphasis for exported light sweet crude because many less complex foreign refineries do not have the ability to manage high iron content adequately. Iron content that exceeds desirable levels could have far-reaching repercussions, from sellers facing financial penalties for not meeting the quality specifications to marine terminals being excluded from the Brent assessment if they miss the mark. It’s a complicated issue, with split views on what causes the iron content in a relatively small subset of Permian oil to be concerningly high — and how best to address the matter. In today’s RBN blog, we look at iron content in crude oil, why it matters to refiners, how it affects prices, and what steps the industry is taking to deal with it.
