Crude oil demand

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.

Crude oil prices continued to increase this week, with WTI at Cushing closing Tuesday at $84.65/bbl, the highest level since October 13, 2014. The rise in crude since the spring of 2020 has been swift and almost relentless, interrupted only by pauses at $40, $60, and $70, when the market took breathers and seemed to say to itself, “We’re not done yet, right?” The question now is, can anything stop WTI from topping $90 and yes, the magic $100 mark — something that few would have predicted we’d see again so soon . The reality is, there are many factors driving crude prices higher but few holding prices down. In today’s RBN blog, we discuss what’s driving the rapid run-up in oil prices, whether $100/bbl WTI is a sure thing, and what happens if — when? — oil hits triple digits.

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.

As the outlook for crude oil in 2022 came into three-dimensional view this month, the market’s steadying mechanism managed to right itself again after another wobble. The Organization of the Petroleum Exporting Countries (OPEC) took its first formal look at next year in its July Monthly Oil Market Report (OMR), becoming the third of three widely watched prognosticators to do so. Among the other two, the International Energy Agency (IEA) began projecting 2022 oil-market data in its June Oil Market Report, and the intrepid U.S. Energy Information Administration (EIA) took its first analytical shot at next year way back in January in its Short Term Energy Outlook. The important third dimension that OPEC gave to the 2022 oil-market picture arrived on July 15 after two weeks of worry about whether production restraint by most of the group’s members and cooperating countries would survive. On July 18, though, the internal squabble driving that concern ended in a compromise that will result in production quota increases for several OPEC+ members. The 2022 projections by OPEC, IEA, and EIA, not to mention worry-driven elevation of crude oil prices prior to the compromise, make clear that the market needs OPEC+ to continue the orderly unwinding of its production cuts. In today’s blog, we compare the three forecasts and look at how the latest adjustment to OPEC+ supply management will affect the market.

Much like the world at large, the crude oil market has been healing from the ravages of COVID-19. Overall, market conditions are far better than they were in April 2020, when global oil consumption, crushed by pandemic-related lockdowns, slumped to 80.4 MMb/d, a 17% decline from the start of last year and a 20% drop from April 2019. Demand has been rebounding in fits and starts for a full year now — recovering from downturns is what markets do. But this recovery has gotten a big assist: 10 members of the Organization of the Petroleum Exporting Countries (OPEC), acting in concert with 10 non-members, have restrained crude oil production in a program unprecedented in scale and duration. Now, oil prices are high enough to revive activity by some producers outside the so-called OPEC+ group. For at least the rest of this year, in fact, the market looks like a steel-cage match between crude supply subject to coordinated management and supply governed only by raw market signals. Today, we look at oil-market projections from three important agencies and estimate demand for oil not supplied by the OPEC+ exporters.

There’s no question, the pressures on many U.S. midstream companies have been steadily increasing for some time now, and the past few months have really tested them. Like exploration and production companies, refiners, and others in the energy space, midstreamers have seen their well-considered plans for 2020 upended by demand destruction, commodity-price gyrations, and cutbacks in capex, drilling, and production. While it may be tempting to simply wait out the last few weeks of this crazy, unforgettable year and hope that 2021 will be better, there’s actually at least some good news out there for the midstream sector, and good reason to believe that midstreamers have been positioning themselves to financially weather whatever next year may have in store. Today, we discuss highlights from East Daley Capital’s newly issued 2021 Midstream Guidance Outlook, which focuses on key trends affecting midstream asset owners.

The offshore Gulf of Mexico is often viewed as the rock-steady player in U.S. crude oil production. Unlike price-trigger-happy shale producers that quickly ratchet their activity up or down, depending on what WTI is selling for that month or quarter, producers in the Gulf base their big, upfront investments in new platforms or subsea tiebacks on very long-term oil-price expectations. Also, unlike shale wells, whose production peaks early then trails off, wells in the GOM typically maintain high levels of production for years and years. But don’t think for a minute that production in the Gulf can’t spike down, if there’s a good reason. GOM output dropped by 300 Mb/d, or 16%, from March to April as producers shut down wells in response to sharply lower oil prices, and a couple of weeks ago more than 80% of GOM wells were taken offline in anticipation of Hurricane Laura. Today, we look at offshore oil production ups and downs in a wild and woolly year and what’s ahead for the GOM.

On Friday, CME/NYMEX WTI Cushing crude oil for April delivery closed at $44.76/bbl, down more than $16/bbl, or about 27%, since New Year’s Day. The declines in natural gas and NGL prices were not quite as severe, but only because those commodities were hit harder than crude during 2019. Even before COVID-19 landed on the market, energy prices were already under pressure from continued record production levels from U.S. shale, weakening demand, a mostly mild winter and a general investor pall over all things carbon. The threat of a global coronavirus pandemic was all it took to push things over the edge. So now what? Of course, nobody knows. But we can contemplate what this all could mean for energy markets, based on what we’ve seen in recent market statistics and price behavior. So that’s what we’ll do in today’s blog.

As a most eventful decade for the U.S. energy industry draws to a close and 2020 looms, it’s a perfect time to consider what’s ahead for the midstream sector — and, more important from an investor’s standpoint, for the individual companies within it. The last few years have driven home the point that while all midstreamers are impacted to some degree by what happens on a macro-level, the relative success of each company is tied to the myriad decisions its leaders make over time regarding which basins and hubs to focus on and which assets to build, expand, acquire or divest. Assessing these micro-level assets and the contributions they each make to a company’s bottom line requires particularly deep analysis. Today, we discuss key themes and findings from East Daley Capital’s newly issued 2020 Midstream Guidance Outlook.

Last week, crude oil prices dropped below $50/bbl, in part due to continued increases in U.S. crude oil inventories, and fell further over the next few days. Then yesterday, prices perked up by $1.14 to $48.86/bbl; again one of the factors was the weekly inventory number from the Energy Information Administration which showed inventories down by a fraction of a percentage point for the week. The market seems to react spontaneously to changes in that crude-stocks statistic. Up is bearish, down is bullish. These days even a very modest decline in inventories is bullish. But serious analysis requires a more detailed, more nuanced understanding of why crude oil inventories behave as they do. Were inventories driven up by higher production or lower refinery runs? By higher imports? By lower exports? The reasons behind the inventory change are more important than the change itself. Today we continue our series on the modeling of U.S. crude oil supply and demand, and the sourcing of input data used in those calculations.