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.
Crude Oil
Back in the early 2000s, the outlook for energy security in the U.S. was bleak. Domestic oil production had been on a steady decline since 1985 and gas production was also well off its apex in the 1970s. M. King Hubbert’s concept of peak oil ignited fears of eventual energy scarcity. Given fossil fuels’ ubiquity underlying our entire Western economic and industrial structure, it’s no wonder that folks were concerned. But then the Shale Revolution changed everything. It’s often been said that necessity is the mother of invention and, after many trials and with considerable ingenuity, U.S. producers learned to wring massive volumes of previously trapped hydrocarbons from shale and gave the U.S. energy industry a new lease on life. But there are still limits on how much crude oil, natural gas and NGLs can be economically produced — and concerns lately that the best of the U.S.’s shale resources may have already been exploited. In today’s RBN blog, we examine crude oil and gas reserves: how they are estimated and what they tell us about the longevity of U.S. production.
Western Canada’s Trans Mountain Expansion Project, better-known as TMX, has experienced more than its share of setbacks over the past 10 years: environmental protests, legal challenges, financing issues, an ownership change, and even a serious flooding event in 2021. But it seems the 590-Mb/d expansion of the now-300-Mb/d Trans Mountain Pipeline (TMP) system will finally become a reality by early 2024, enabling large-scale exports of Alberta-sourced crude oil to Asian markets. There’s a catch, though. The project’s long delays and other issues resulted in massive cost overruns that are now being reflected in the preliminary tolls for the soon-to-be-combined Trans Mountain system. The proposed toll increase is so large that it will cost a similar amount to ship heavy crude oil to tidewater on Trans Mountain as it would on the competing Enbridge system to the U.S. Gulf Coast for “re-export,” despite the latter being three times the distance. In today’s blog, we discuss the history of the Trans Mountain expansion, its cost overruns and the calculations that went into the proposed tolls — the kicker being that those tolls could end up being even higher.
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.
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.
The energy industry is evolving rapidly, spun forward by a wide range of forces: a pandemic and its aftershocks, tensions with China, a land war in Europe and a push to decarbonize, to name just a few. What’s emerged in the last couple of years is an industry starkly different than the one that existed before. Every link in the value chain — from the producers upstream, to midstreamers, to the refiners and exporters downstream — has had to drastically adjust their strategies and, if anything, these changes have only intensified the connectivity across the markets for crude oil, natural gas, NGLs and refined products. It has underscored the need for industry participants to see and understand those links and how they impact their businesses. There’s a lot at stake. The energy industry of the mid-2020s — yes, we’re already in the middle third of the decade! — is vastly different, and so are the challenges, as we examine in today’s RBN blog.
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.
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.
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?
A long-planned ship-channel deepening and widening project in Corpus Christi Bay is in its last innings and is about to start having a real impact. Later this summer, a 7-foot-deeper channel at Ingleside will enable terminals there to load additional barrels into VLCCs, assuming they’ve dredged their berths to match the deeper channel. Deepening the channel to 54 feet (from the old 47 feet) also will enable terminals that have deepened their berths to fully load 1-MMbbl Suezmaxes, up from the 800-850 Mbbl that can be loaded now. Crude oil export economics in South Texas will get another boost in late 2024 when the fourth and final portion of the $680 million dredging project is completed. In today’s RBN blog, we discuss the dredging project, its steady progress, and its impact on the “battle for barrels” among Corpus, the Houston area and a quartet of proposed offshore terminals.
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.
A long-planned ship-channel deepening and widening project in Corpus Christi Bay is in its last innings and is about to start having a real impact. Later this summer, a 7-foot-deeper channel at Ingleside will enable terminals there to load additional barrels into VLCCs, assuming they’ve dredged their berths to match the deeper channel. Deepening the channel to 54 feet (from the old 47 feet) also will enable terminals that have deepened their berths to fully load 1-MMbbl Suezmaxes, up from the 800-850 Mbbl that can be loaded now. Crude oil export economics in South Texas will get another boost in late 2024 when the fourth and final portion of the $680 million dredging project is completed. In today’s RBN blog, we discuss the dredging project, its steady progress, and its impact on the “battle for barrels” among Corpus, the Houston area and a quartet of proposed offshore terminals.
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.
Consider this fact: Three of every five barrels of crude oil produced in the U.S. are exported, either as crude oil or in the form of gasoline, diesel, jet fuel or other petroleum products. Sure, large volumes of crude and products are still being imported, but the net import number is dwindling toward zero — and if you count NGLs (ethane, propane, etc.) in the liquid fuels balance, the U.S. has been a net exporter since 2020. Yes, folks, exports are now calling the shots, and the role of exports is only going to become larger over the next few years. In today’s RBN blog, we discuss highlights from our recent Drill Down Report on crude oil and product exports and why they matter more now than ever.
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.