Crude oil supply

Strategic Petroleum Reserve (SPR) inventories have been climbing over the past year as the Department of Energy (DOE) advances plans to replenish it following the record 180-MMbbl drawdown after Russia’s invasion of Ukraine in 2022. But DOE officials have said its refilling efforts are complicated by upgrades at three of the four SPR storage sites. In today’s RBN blog, we look at the scope of these “life-extension” projects, the completion timetable, and how it might drag out restocking efforts. 

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.

After the crude oil price crash in the spring of 2020 and flat-at-$40/bbl oil last summer and early fall, prices for both WTI and Brent have been increasing steadily the past several months, and now stand at a kind-of-remarkable $75/bbl. This rise has been driven by a combination of demand recovery and supply restraint from both OPEC+ and U.S. producers — which begs the questions: what’s next on the supply and demand fronts, and how much more will oil prices increase from here? There’s been a lot of chatter lately that we might see $100/bbl crude prices sometime soon, and there are a lot of interested parties — many of whom don’t normally see eye-to-eye — who, for one reason or another, see their interests converge around the $100/bbl mark. The only problem is, it’s not showing up in the forward curve. Today, we look at the potential for “Benjamin-a-barrel” oil and how it might play out.

Earlier this decade, East Coast refineries found it cost-effective to ramp down their crude imports and turn to the price-advantaged U.S. shale oil they could rail in from the pipeline-constrained Bakken or send up by tanker from the crude-saturated Gulf Coast. Things changed, though. New southbound crude pipelines out of the Bakken came online, the ban on most crude exports was lifted — providing a new outlet for Texas crude production — and the economic rationale for railing or shipping in domestic crude to PADD 1 refineries withered. Now, things have changed again. Most important perhaps, is that the price spread between WTI and Brent has widened, and once more it can make financial sense for these refineries to revert to crude-by-rail out of the Bakken and to shipping in crude on Jones Act tankers from Corpus Christi and other Gulf Coast ports. Today, we discuss these recent trends, what’s driving them, and how long they might last.

Crude oil production in the Western Canadian Sedimentary Basin (WCSB) has risen by more than 50% over the past seven years to about 4 MMb/d, driven by new projects and expansions in the oil sands of Alberta. And while growth has slowed since the 2014-15 downturn in crude oil prices, oil sands output is expected to continue climbing — particularly over the next year as the new, 194-Mb/d Fort Hills project ramps up toward full operation. Most forecasts put total WCSB production at near 5 MMb/d by the mid-2020s. But while Western Canadian crude oil supply has been rising, there has been only a modest expansion of pipeline capacity out of the region, and lately takeaway constraints have had a devastating effect on the price relationship between benchmark Western Canadian Select (WCS) and West Texas Intermediate (WTI). Today, we continue our series on Canadian crude and bitumen production, existing and planned pipelines, and the effects of takeaway constraints on pricing, this time focusing on the supply side of the story.

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.