The global oil market has been especially volatile this year, but the United Arab Emirates’ decision to cease its OPEC membership provided another jolt. Today, we dig into why the UAE chose this path and the potential implications for the global market and U.S. producers.
The West Coast energy market, PADD 5, is undergoing a profound transformation. Consumption of petroleum-based refined products is declining due to a host of factors including increased renewable diesel (RD) usage, slowing population growth, electric vehicle (EV) penetration and fuel efficiency improvements, just to name a few, but that’s only half the story. Further upping the stakes, crude oil production in the region has declined faster than downstream consumption, so it has had to increasingly rely on imported barrels to support its dwindling refinery throughput. In today’s RBN blog, we look at how the West Coast’s supply of refined products and crude oil has evolved over time and why its reliance on imports has grown.
PADD 1 — the East Coast — represents about 31% of total U.S. consumption of refined products (and 37% of its population) but is home to just 5% of U.S. refinery capacity. With only minimal in-region crude oil production, PADD 1 refineries are almost entirely dependent on imported and domestic inflows of both crude oil and products like gasoline, diesel and jet fuel. In the early years of the Shale Era, large volumes of domestic crude were railed or barged to these refineries, but in recent years they’ve again become largely reliant on imports from OPEC, Canada and other foreign sources. In today’s RBN blog, we’ll look into PADD 1’s changing crude oil and refined products supply and demand balance.
The Biden administration has been on a mission for more than a year to restock the Strategic Petroleum Reserve (SPR), which was tapped at unprecedented levels in an effort to keep crude oil and refined product prices under control after Russia’s invasion of Ukraine in early 2022 disrupted energy flows globally. But if returning all of the released 180 MMbbl and replenishing the SPR to pre-war levels was the plan, they’ve got a long way to go. In today’s RBN blog, we examine the steps the administration has taken to replenish the reserve and the headwinds it faces.
For many years now, the U.S. has been buying — and piping or railing in — virtually all of the crude oil Canada has been exporting, in part because Canadian producers have only very limited access to coastal ports. More recently, greater pipeline access from the Alberta oil sands to the U.S. Gulf Coast (USGC) has created an attractive pathway — a “Carefree Highway,” if you will — for Canadian crude oil to be “re-exported” to overseas customers. This year, much stronger international demand has sent re-export volumes to record highs — and provided Alberta producers very attractive price differentials for their oil sands crude. That overseas demand appears to be sustainable, but with the looming startup of the 590-Mb/d Trans Mountain Expansion Project (TMX), which will increase the capacity of the Trans Mountain Pipeline system to 890 Mb/d and enable much more Alberta crude to be exported from docks in British Columbia, the re-export surge from the USGC may be in for a pullback, as we discuss in today’s RBN blog.
The global reaction to Russia’s invasion of Ukraine was swift, with calls of condemnation and plans quickly surfacing for the U.S. and other countries to stop their purchases of Russian crude oil and natural gas immediately, or at least as soon as practical. The strategy has been to make the situation as politically and financially painful as possible for Russia, which has not been shy about using its energy supplies as a weapon, before or after the invasion. But those plans haven’t worked as well as hoped, and some impacts are bringing back memories of the 1973 oil embargo which, though driven by a far different series of events, may provide insight into the current situation. In today’s RBN blog, we look at the many parallels to today, including weaponized oil, regional supply shortages, price spikes and well-intentioned (if sometimes ill-conceived) government responses.
There is a fundamental difference in the way value is established in renewable, decarbonized energy markets versus traditional commodities. In traditional energy markets, value is defined by natural laws — physics, chemistry, geography. But in the world of renewables and decarbonization, value is primarily determined by man-made laws — RULES that specify what a particular flavor of energy is worth, what is required to prove that worth, and how that value is ultimately captured by market participants. In effect, a molecule’s (or electron’s) pedigree is as important — if not more important — than its energy content. Whether you are deep into renewables markets or you deal with energy commodities that are impacted by the rules, it is critically important that you understand everything about how these rules work and how they are regulated. In today’s RBN blog we’ll begin an exploration into the inner workings of energy transition market mechanisms.
The November 4 decision by the Organization of the Petroleum Exporting Countries and its collaborators — collectively known as OPEC+ –– to stay the course on crude oil production surprised few and disappointed many. Officials from leading oil-consuming nations, including the U.S., Japan and India, want the group to relax its production restraint by more than the scheduled 400 Mb/d in December. They see extra crude supply as an antidote for high prices that have been hampering recovery from the global economic slump caused by the COVID-19 pandemic. But OPEC+ leaders made clear that they’re in no mood to accelerate their phase-out of production cuts. They know the market pressures now elevating crude prices won’t last forever and can change unexpectedly. They also face internal strains that might weaken the quota discipline that has kept the group’s supply management intact, despite the occasional upset, for nearly five years. One of those strains is the number of OPEC+ participants already producing as much crude as they can while falling short of existing ceilings — a number that grows as the ceilings rise. Today’s RBN blog looks at oil-market expectations underlying OPEC+ members’ cautious approach and at the growing divide among those unable to keep up with output targets and the relatively few but volumetrically overpowering counterparts with capacity to spare.
This summer’s resurgence of the COVID-19 pandemic in many parts of the world will wreck forecasts of demand for petroleum products and, therefore, for crude oil. Most oil-market forecasts published in the first half of 2021 didn’t anticipate the 75% jump in new weekly coronavirus cases that has occurred since mid-June, or new possibilities for travel limits and other restrictions of the type that clobbered economies — and oil demand — around the globe in 2020. Obviously, swerves away from expectations for oil consumption scramble the supply-demand balances widely used in oil-market analysis. But they do happen. In fact, deviation between forecast and actual demand is the rule, not the exception. It’s just not always as extreme as the balance adjustments likely to be needed after the latest COVID surprise. Even when there’s no deadly pandemic to worry about, demand can be tricky to define, difficult to measure, and frustrating to predict. In today’s blog, we discuss the intricacies of oil-demand assessment and explain why balance calculations, based on forecasts destined to be wrong, remain meaningful to analysts mindful of their limitations.
