Daily Energy Blog

Global crude oil markets are undergoing a profound transformation. But it is mostly out of sight, out of mind for all but the most actively involved players in the physical markets. On the surface, it’s a simple change in the Dated Brent delivery mechanism: Starting May 2023, cargoes of Midland-spec WTI — we’ll shorten that to “Midland” for the sake of clarity and simplicity — could be offered into the Brent Complex for delivery the following month. This change has been in the works for years. Production of North Sea crudes that heretofore have been the exclusive members of the Brent club has been on the decline for decades. Allowing the delivery of Midland crude into Brent is intended to increase the liquidity of the physical Brent market, thereby retaining Brent’s status as the world’s preeminent crude marker, serving as the price basis for two-thirds or more of physical crude oil traded in the global market. So far, the new trading and delivery process has been working well. Perhaps too well. For the past two months, delivered Midland has set the price of Brent about 85% of the time. The number of cargoes moving into the Brent delivery “chain” process has skyrocketed, and most of those cargoes are Midland. Is this just an opening surge of players trying their hand in a new market, or does it mean that the Brent benchmark price is becoming no more than freight-adjusted Midland? In today’s RBN blog, we’ll explore this question, and what it could mean for both global and domestic crude markets.

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.

U.S. refiners have been enjoying some very good times the past couple of years. Most important, refining margins have soared due to a tight global product supply/demand environment brought on by, among other things, the post-COVID demand recovery, refinery shutdowns, Russia/Ukraine war effects, and high natural gas prices. Traditionally, the bulk of refining margins have come from (1) robust “crack spreads” (the general yardstick for measuring overall refining sector health, simply by taking the difference between a basket of refined products and key light sweet crude markets like WTI Cushing or MEH) and (2) the lower crude-input costs that many refineries benefit from, either because of location-related advantages or their ability to process lower-cost crude like medium and heavy sours. But location discounts have narrowed in recent years due to the buildout of pipelines and, as we discuss in today’s RBN blog, the big quality discounts that complex refiners relished through much of last year and the first few months of 2023 have withered. The question is, why?

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.

It took a while, but Enbridge and shippers on its 3.2-MMb/d Mainline system have finally reached an agreement in principle on a new tolling agreement that will lower per-barrel rates on the mammoth crude oil pipeline network between Western Canada and the U.S. Midwest — and also help ensure that Enbridge will earn a healthy rate of return on its largest asset. Assuming the Mainline Tolling Agreement (MTA) is approved by Canadian regulators later this year (and that’s seems to be a safe bet), the new rate structure should also help the Mainline system retain the vast majority of its crude volumes, even as it faces new competition from the Trans Mountain Expansion (TMX) project, which will provide 590 Mb/d of additional pipeline capacity from Edmonton, AB, to the British Columbia (BC) coast starting sometime next year. In today’s RBN blog, we discuss the MTA and what it means for Enbridge, shippers and TMX.

Only 20 years after Colonel Edwin Drake drilled the first commercial oil well in Titusville, PA, in 1859, the U.S. was responsible for 85% of global crude oil production and refining. But over the next century, the country became increasingly dependent on oil imports — concerningly so at times. Thanks to the Shale Revolution, the U.S. is now on the verge of a sea change in the supply-and-demand dynamics for crude oil, gasoline, diesel, jet fuel and other petroleum products. In the coming years, as U.S. crude production continues to increase, essentially all incremental barrels will flow to export markets, possibly through one or more of the new offshore terminals under development off the U.S. Gulf Coast. Export growth — and the midstream infrastructure needed to facilitate it — was one of many topics covered at our recent xPortCon 2023 and the subject of today’s RBN blog, which also announces the availability of videos from last Thursday’s packed-to-the-gills conference.

Crude oil quality has been a hot topic lately. With the increase in waterborne activity along the Gulf Coast, a high-quality barrel is desired now more than ever. Permian WTI exports have continued to increase as production rises and refining capacity remains relatively stagnant (outside of ExxonMobil’s recent Beaumont expansion). This has resulted in more scrutiny on Permian quality and more concerns rising to the surface — both from the pockets of lower-quality WTI produced at the wellhead and from blending by market participants, as many midstream providers and traders have become efficient at capturing arbitrage opportunities. Recent WTI quality concerns have primarily been around metal content, hydrogen sulfide (H₂S) and mercaptans, while nitrogen has become a major issue in the natural gas market. In today’s RBN blog, we look at the issue of mercaptans in WTI.