Today’s column is from Ben Samuels.
Oil and gas derivatives are ubiquitous in every corner of the globe, with the resource accounting for an incredibly vast and diverse set of goods, services and essentials for survival and prosperity in use today. Since the 1980s, S&P Platts has utilized Dated Brent to establish a benchmark commodity price in order to set the global market prices, facilitate trade more easily (used to establish pricing for over half of global physical crude transactions), provide stability for resource production expectations, modulate capital investment and more. As the evolution in the energy markets has progressed in time, the scope of this metric has been expanded to incorporate the pricing reflected from four other North Sea fields (Forties, Ekofisk, Oseberg and Troll). While the North Sea has been a mainstay in the market for decades, its’ production has declined precipitously in recent years, resulting in much less liquidity in the futures and trading markets. When this is coupled with the plan to abandon future resource development in the region and the shale boom in the United States, the winds of change began to blow more vigorously.
Beginning in 2018, S&P Platts announced intentions to open up conversations regarding restructuring the pricing index to include WTI Midland as a more reliable and robust reflection of commodity pricing, so it was no surprise when there was an announcement in late February this year regarding an update to this nebulous conversation. While the inclusion of WTI Midland, slated to begin in July 2022, has been expected and would be welcomed into the indexing formula, an indication that S&P Platts may transition from a FOB (free on board) basis to CIF (Cost, Insurance and Freight) terms were met with much less enthusiasm. This shift would arguably make the benchmark less reliable due to the fluctuation in variable costs of shipping and insurance and would artificially inflate the commodity price(s) to accommodate for the adjustment. The pushback on the announcement was so fervent that S&P shelved the idea, in order to solicit more feedback from the market participants, less than three weeks later.
The Permian Basin (the source of WTI Midland) region already provides approx. 500k BPD to the European markets, which is equivalent to ~60% of the current volumes produced from the five North Sea Brent fields combined. The addition of these WTI Midland volumes into the Brent pricing calculus would provide increased stability and liquidity to a market somewhat unfamiliar with the former and craving the latter. *
While Brent production volumes have fallen precipitously, the shale boom in the United States has picked up the slack more easily than other regions due to the similar composition profile of the crude produced. "Next year, we see North Sea production falling below one cargo per day in the BFOET benchmark grades so timeline is there any way in the fundamentals," Jonty Rushforth, a senior director in the Platts price group, said. While there seems to be a consensus that the pricing model needs to be updated to reflect current market dynamics, the mechanics of how to implement those changes remain up for debate.
“The new Platts proposal for Brent dated and cash (BFOE) assessment is nothing short of revolutionary. It is not surprising that it caused such an uproar,” Adi Imsirovic, senior research fellow at the Oxford Institute for Energy Studies, wrote last week.
“The key problem with the proposal is it would likely undermine and possibly destroy the forward Brent market. The whole plethora of derivatives contracts … would probably change or disappear.”
In response to the S&P Platts announcements to adjust the benchmark, there were a litany of market participants who proposed solutions. One of these, from Trafigura -- one of the world’s largest commodity trading and logistics houses, was to utilize data from their Corpus Christi, Texas hub to anchor a new pricing model as current volumes processed there are roughly 300k BPD greater than the current cumulative North Sea production (from the five fields used to establish Brent). Other proposals include incorporating data from either Russian or West African fields, which would seem to invite a host of other geopolitical and reliability issues that could harm the efficacy of the Brent index which would be detrimental to all participants.
In further reference to reliability, the domestic market did not do itself any favors on the global stage in April 2020, as WTI prices plunged to (-$37) oil due to storage and supply/demand constraints exacerbated by the coronavirus lockdowns, but also due, at least, in part to logistical issues within the framework of the domestic crude transport infrastructure that has created bottlenecks in the process of supplying various regions with the necessary volumes cost-effectively. If WTI Midland is going to be relied upon as part of the dated Brent calculus, the United States will need to expand the Cushing, OK hub, and incorporate other similar infrastructure support to broaden that scope and mitigate capacity and other logistical issues at hand. Does the current administration have the appetite for this? Don’t hold your breath.
“After the WTI crude’s historic plunge to negative territory, energy traders’ frustration peaked with the dependence of oil delivery rules and storage capacity problems to a single location in Oklahoma,” said Edward Moya, senior market analyst with OANDA. “Brent crude didn’t have the same problem as WTI, and investors will welcome a US waterborne benchmark.”
This conversation will be a key story to track over the next few years as we continue to constrict drilling programs domestically and other market participants race to fill that gap and accrete the requisite power that position holds. For the time being, the market has restabilized as the impending changes have been couched until a consensus can be reached, which is a far cry from the initial announcement from Platts of an indication to make the changes rather suddenly. Will the US continue to give up market share in deference to virtue signaling or will we step up to the plate and maintain our position on the global energy stage by becoming a more integral cog in the crude pricing wheel?
* Note: Before people start to connect the dots here, let’s consider the domestic production curtailment and the associated need to increase crude imports, especially to the virtue-signaling regions of the country i.e. the Northeast, where regulators and legislators have begun to ban new, and in some cases the use of existing, natural gas infrastructure in construction and other development projects. According to the EIA, 2020 was the first time that the United States was a net petroleum exporter; expect that to change in 2021-2023 (at a minimum).