differential

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. 

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?

There is no debate about it: The CME/NYMEX domestic sweet (DSW) crude oil futures prompt-month contract at Cushing, OK, is the most closely followed benchmark in U.S. energy markets. It’s the price quoted in nightly news reports and general media publications. And now, with U.S. exports of WTI deliverable on the Brent contract, domestic sweet at Cushing is arguably setting the price for crudes around the world. But the fact is, most crudes traded in physical markets across North America are not priced at the DSW-at-Cushing benchmark but instead at a differential to Cushing — higher or lower on any given day based on each crude’s unique quality, location, and supply/demand characteristics. In today’s RBN blog, we discuss how the behavior of differentials from the Cushing benchmark can go a long way to explain what is happening with crude oil production, transportation volumes, storage and, of course, exports.

The market is used to crude oil spreads in the Permian Basin being volatile. Fast-paced production growth, the addition of new takeaway pipelines — and the rapid filling of those new pipes — have all impacted in-basin pricing, and we’ve seen differentials from the Permian to its downstream markets — Cushing, OK, and the Gulf Coast — widen and narrow as supply and demand fundamentals have changed. But recently, things have gotten a lot wilder. In September 2018, the Midland discount to WTI at Cushing blew out to almost $18/bbl, then narrowed to less than $6/bbl only three weeks later, thanks largely to the start-up of Plains All American’s much-ballyhooed, 350-Mb/d Sunrise Expansion. As Sunrise started to fill up, price differentials initially widened for a brief period of time. But, as we kicked off 2019, the Midland-Cushing spread quickly shrank further and then flipped, with Midland last Friday (January 25) trading at a $1/bbl premium to Cushing crude. You might wonder, how the heck did that happen? In today’s blog, we discuss how things play out when a supply glut evaporates and traders are suddenly caught in a tight market.

The physical market for Brent, Forties, Oseberg and Ekofisk (BFOE) represents the delivery mechanism for ICE Brent Futures and is linked to crude oil contracts worldwide. This year the  trading in the BFOE forward market has been limited to just 20 cargoes a month from the Forties stream. Today we describe producer’s efforts to increase market liquidity.

This is Part 3 in our series on the physical Brent crude market. What follows will make more sense if you read Part 1 and Part 2 first. In Part 1 we explain that the Brent crude used as a benchmark for international pricing that underlies the ICE Brent futures contract – is made up of crude oil produced in dozens of different North Sea fields and delivered to market in four different streams – Brent, Forties, Oseberg and Ekofisk (BFOE). In Part 2 we explain the linkage between the small Brent physical crude market that trades in 600 MBbl parcels costing upwards of $60 MM at today’s prices and the Brent ICE futures contract that trades in 1000 Bbl lots. Prices in the two markets are linked together by a cash settlement process using a Brent Index price based on forward trades in the physical market. The Brent Index settlement is an exchange for physical  (EFP) mechanism that ensures convergence between futures and physical markets.

The convergence mechanism in futures markets used to be something taken for granted in international crude trading. Futures exchanges like ICE and the CME NYMEX were considered an add-on service for the oil industry to hedge price risks - secondary to the physical market. That was the old days. Now futures trading volumes dwarf physical market transactions (in Part 2 we showed that ICE Brent futures trades 500 times the physical BFOE crude production volumes each day). Nevertheless the futures contracts still have to relate back to underlying physical crude oil prices in order to function efficiently. That can sometimes cause unexpected results.

You may have heard that Cushing, Oklahoma is no longer the center of the crude oil universe.  The logic goes that WTI is no longer representative of the world crude oil price. …The WTI-Brent arbitrage is broken.  …NYMEX and ICE are looking for trading hubs to replace Cushing.  ….The days of WTI as a hedging vehicle for everything between jet fuel in Wisconsin to crude oil production in Latin America are ancient history.  ….Rail cars from the Bakken are moving to St. James, LA or Albany, NY.  …Certainly not Cushing, OK.   ….All the shale oil barrels want to get to the huge Gulf Coast refinery complex, bypassing Cushing.  ….It is only a matter of time before Cushing devolves into a dusty Oklahoma town with a lot of rusting tanks.   …And all crude oil will trade against St. James, or Brent, or some new Gulf Coast index.