WTI

A macro view of U.S. exploration and production (E&P) company performance over the last quarter century reveals repetitive boom-and-bust cycles driven by periodic extremes in crude oil pricing, including price crashes in 2008, 2014 and 2020. That history contrasts with the remarkable stability in West Texas Intermediate (WTI) realizations since mid-2021 as the industry got its footing post-pandemic. Assisted by a new commitment to financial discipline, producers have generated relatively stable, historically solid overall quarterly earnings and cash flows. But the devil’s in the details, and in today’s RBN blog we delve into peer group and individual company performance as well as overall industry trends for Q1 2024. 

If you asked someone where U.S. crude oil shipments would go when the Obama administration ended the ban on most crude exports in December 2015, it’s not likely that Nigeria would have come to mind. Yet this year marked the second time since the restrictions ended that U.S. oil has been sent to the OPEC member, this time to feed its long-awaited Dangote refinery. In today’s RBN blog, we will examine this development and the prospects for more U.S. exports to the West African nation. 

In the race to build the next deepwater crude oil export terminal in the Gulf of Mexico, Sentinel Midstream’s proposed Texas GulfLink (TGL) is currently in second place in the regulatory race, behind only Enterprise’s Sea Port Oil Terminal (SPOT) — and seems to be emerging as a serious contender. The plan offers some compelling attributes, including Sentinel’s status as an independent midstream player and plenty of pipeline access to crude oil volumes in the Permian and elsewhere. In today’s RBN blog, we turn our attention to TGL and what it brings to the table. 

In the race to build the next deepwater crude oil export terminal along the U.S. Gulf Coast, there’s a lot of competition but one project now has a clear advantage: Enterprise Product Partners’ planned Sea Port Oil Terminal (SPOT), which has made the most progress in moving through the regulatory morass and announced that it had received its deepwater port license on April 9. In today’s RBN blog, we provide an update on SPOT’s progress and look at some of its inherent advantages, including a potentially shorter time to market and extensive pipeline connectivity. 

With many years gone by and many millions of dollars spent, the deepwater crude oil export projects under development along the U.S. Gulf Coast are finally getting close to receiving their regulatory green light. These projects have sparked commercial and wider market interest because of the many benefits they may provide — including the ability to fully load the biggest tankers, the Very Large Crude Carriers (VLCCs) capable of taking on 2 MMbbl, which could contribute to lower per-barrel shipping costs. In today’s RBN blog, we kick off an offshore oil terminal series, starting with the case for constructing at least one of the export projects. 

As U.S. crude oil expands its foothold across the world, the markets that trade it have undergone some fundamental changes. Since the onset of the pandemic almost four years ago, these changes have included the shortening of the loading-date range for crude oil cargoes marketed along the U.S. Gulf Coast. Price reporting agencies (PRAs) like Argus have responded, launching crude oil assessments that reflect a narrower loading window. In today’s RBN blog, we take a closer look at the changes and the new assessments Argus has rolled out to help crude oil traders manage their market exposure. 

Fresh on the heels of expanding its Beaumont, TX, refinery into the largest in the country, ExxonMobil announced in January that it had finished yet another project at its century-old Baton Rouge complex in Louisiana. The Baton Rouge Refinery Integrated Competitiveness (BRRIC) project took roughly three years to complete and did not add crude refining capacity, unlike the Beaumont project. Instead, the goal of the $240 million investment was to modernize the crude oil processing plant — the state’s largest — increasing access to competitive crudes and growing markets for its fuels as well as curbing the refinery’s environmental impact. In today’s RBN blog, we take a closer look at the BRRIC project and what it means for the Baton Rouge refinery. 

Think energy markets are getting back to normal? After all, prices have been relatively stable, production is growing at a healthy rate, and infrastructure bottlenecks are front and center again. Just like the good ol’ days, right? Absolutely not. It’s a whole new energy world out there, with unexpected twists and turns around every corner — everything from regional hostilities, renewables subsidies, disruptions at shipping pinch points, pipeline capacity shortfalls and all sorts of other quirky variables. There’s just no way to predict what is going to happen next, right? Nah. All we need to do is stick our collective RBN necks out one more time, peer into our crystal ball, and see what 2024 has in store for us. 

Wider price discounts for Western Canadian heavy crude oil have been weighing on its oil producers for the past few months. This appears to be the result of a combination of weak refinery demand, rapidly rising oil production and insufficient oil takeaway capacity from Western Canada. A more permanent solution for wider discounts might be to increase pipeline export capacity to ensure that rising oil production has more options to reach markets. In today’s RBN blog, we consider the pending startup of the Trans Mountain Expansion Project (TMX) as a means to do just that.

The price discount for Western Canada’s benchmark heavy crude oil has seen yet another widening in the past few months. Increased pipeline access to the U.S. was believed to be the key to solving this problem in the long term, but more recent fundamental developments surrounding pipeline egress, refinery demand and increasing heavy oil supplies demonstrate that larger discounts can — and do — still happen. This problem could persist for several more months until a better balance is achieved in downstream markets. In today’s RBN blog, we discuss the latest drivers of the wider price discounts for Western Canada’s heavy oil. 

Over the past three-plus years, Corpus Christi has dominated the U.S. crude oil export market, largely because of the availability of straight-shot pipeline access from the Permian to two Corpus-area terminals at Ingleside — Enbridge Ingleside Energy Center (EIEC) and South Texas Gateway (STG) — that can partially load the huge 2-MMbbl VLCCs (Very Large Crude Carriers). But capacity on the pipes to Corpus is now nearly maxed out and, with Permian production rising and exports strong, an increasing share of West Texas crude output is instead being sent to Houston on pipelines with capacity to spare. The catch for Permian shippers with capacity on Permian-to-Houston pipes is that the Midland-to-MEH (Magellan East Houston) price differential for WTI has been depressingly low —$0.22/bbl on average this year, compared to almost $20/bbl for a few months in 2018 and averaging $5.50/bbl as recently as 2019. However, the Midland-to-MEH WTI price spread looks to be on the verge of a rebound of sorts, as we discuss in today’s RBN blog.

The level of activity at crude oil export terminals from Corpus Christi to the Louisiana Offshore Oil Port (LOOP) is nothing short of extraordinary — a record 4.8 MMb/d was loaded the week ended August 25, according to RBN’s Crude Voyager report, and Houston-area terminals loaded an all-time high of 1.4 MMb/d. But there’s a lot more to the crude exports story. When you live this stuff day-in, day-out, you see subtle changes that often extend into trends and, if you’re lucky, you sometimes get signals that things you’d been predicting are actually happening. In today’s RBN blog, we discuss highlights from the latest Crude Voyager and what the weekly report’s data and analysis reveal about the global oil market.

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.

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.

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.