COVID-19

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.

Crude oil is demonstrating yet again its penchant for what markets hate most: surprise. Last month, the Organization of the Petroleum Exporting Countries (OPEC) and collaborating governments were carefully easing the production cuts with which they steered the market through an oil-demand crisis caused by the COVID-19 pandemic. Demand was recovering as economies reopened after being locked down during most of 2020 and early 2021. And the near-month futures price for light, sweet crude on the New York Mercantile Exchange (NYMEX) — having closed below zero for the first time ever on April 20, 2020 — rose above $70/bbl for the first time since October 2018. Until mid-June, the market’s main concern was the potential for a supply surge if Iran escaped sanctions by agreeing with the U.S. to again suspend nuclear development. Surprise! Only days after his election as Iranian president on June 18, Ebrahim Raisi announced new limits on what his government would negotiate regarding nuclear work and said he would not meet with U.S. President Joe Biden. Suddenly, new oil supply from Iran looked less imminent than it did before Raisi’s election. Then July arrived. Surprise! OPEC members and nonmembers, collectively known as OPEC+, which had been voluntarily limiting production ended an important meeting without agreeing, as had been expected, to extend their phasedown of supply restraint. Suddenly, the market had to wonder whether the result would be too little supply or a price-crushing production spree if OPEC+ discipline collapsed. In today’s blog, we examine how these developments relate to each other in the twin contexts of a rebalancing oil market and of past oil-supply management.

As the U.S. starts to emerge from under the dark cloud of the COVID-19 pandemic, one hopes that some valuable lessons have been learned as a result of the hardships and sacrifices so many have endured.  While the most profound impacts were on government, healthcare and other essential services, the sudden drop in hydrocarbon demand a year ago triggered severe financial hardships for the E&P sector and provoked unpleasant memories of previous energy industry crises in 2008 and 2014-16. Producers have historically put the brakes on capital spending when commodity prices fell, then stomped on the accelerator like a race car heading into a straightaway when prices rose. But recently unveiled 2021 budgets for many E&Ps suggest that, even with the rebound in prices, they are maintaining a conservative investment paradigm that highlights strengthening balance sheets and rewarding shareholders at the expense of rapid production growth. Today, we’ll analyze the 2021 capital spending plans of the 39 E&Ps we monitor and the likely impact on their crude oil and natural gas output.

Just one year ago, the onset of the COVID-19 pandemic plunged the energy industry’s exploration and production (E&P) sector — already reeling from a steep decline in oil prices in late 2019 — into a memorably brutal spring that threatened its survival. Demand cratered, price realizations fell to the lowest point in a decade, and cash flows dried up. Sure enough, E&P results for the first half of 2020 were a train wreck, with the three-dozen companies we track reporting a whopping $45 billion in losses, including impairments. But the dark clouds hovering over the industry began to clear in the second half of the year as the combination of production cutbacks and recovering demand triggered rising prices.  With the massive price-related impairments largely in the rear-view mirror, year-end 2020 results revealed that most E&Ps had clawed their way back to near-profitability. Today, we review their latest numbers and preview what we expect will be a sunny 2021 for the industry.

Well, here we are. The last day of 2020. We are tempted to say “unprecedented” to describe the year. But the word is so overused — there’s been an unprecedented use of the word “unprecedented” — let’s just say it will be good riddance to have this one behind us. After all, we’ve seen a collapse in transportation fuel demand, an oil price war between major producers, negative $37/bbl crude prices, massive LNG cargo cancellations — the list goes on — all in the context of a global pandemic and much of the world committed to weaning itself off fossil fuels over the next few decades. How do you make sense of all that? How do you anticipate when it’s going to be “all right” again? Well, one thing we can do is to heed the events and trends that captured the market’s attention during all this chaos. In other words, to put a spotlight on the things that the market considers top priority — crowd-sourced market intelligence, if you will. Well, at RBN we have one way to do that. We scrupulously monitor the website hit rate of the RBN blogs that are fired off to over 30,000 people each day and, at the end of each year, we look back to see which topics generated the most interest from you, our readers. That hit rate reveals a lot about major market trends. So, once again, we look into the rear-view mirror to check out the Top 10 blogs of the year based on the number of rbnenergy.com website hits.

No one could’ve seen the energy market disruptions of 2020 coming, and most of us are ready to write off what has been one of the most challenging years the industry has seen in a long time. Yet the events of the past year will most certainly define what unfolds in the New Year and beyond. To make sense of what 2020 will mean for the post-COVID era, we retooled and refreshed our models and forecasts to tackle the hard questions facing U.S. crude oil, natural gas, and NGL markets. As it turns out, beyond the immediate chaos of the pandemic, there is a new order taking shape, and that’s what we laid out in the RBN Fall Virtual School of Energy, sharing our results and the Excel spreadsheets behind the models to get you ready for what’s coming. Some of what we expected has come to fruition, and we still think that there is a pretty good chance that the rest will unfold in the months and years ahead. If you weren’t able to join us for the live broadcast, we invite you to sit by the fire, put your feet up and dig in over the holidays. The entire 14+ hours of streaming content, plus slide decks and spreadsheets, are available online. Today’s advertorial blog provides highlights from our key findings and the overall conference curriculum.

Western Canada’s relentless, decade-long increase in crude oil production began maxing out its export pipeline capacity in the past few years. With more supply than could be carried by pipelines, exporting crude by rail tank car became the next best alternative, leading to record amounts of rail-based exports earlier this year. However, this year’s wild swings in oil prices and COVID-led demand destruction resulted in drastic production cutbacks that freed up space on pipelines and put the kibosh on more expensive crude-by-rail, at least temporarily. Things are shifting again, though. With oil production recovering somewhat in the past couple of months and excess pipeline capacity dwindling, are we headed for a resurgence in the use of rail to export Canadian crude? Today, we conclude a series on Western Canada crude production and takeaway options with an analysis of what’s ahead for crude-by-rail.

No one in North America’s energy sector is likely to forget the second quarter of 2020 anytime soon. In those months — April, May, and June — the demand-destruction effects of the COVID-19 pandemic took root; the price of West Texas Intermediate (WTI) bottomed out, even going negative for a day; and crude oil-focused drillers in particular shut in vast numbers of wells. In late July and August, when exploration and production companies (E&Ps) announced their results for that train wreck of a quarter, it came as no surprise that the write-downs and losses were generally immense and, in many cases, record-shattering. But WTI prices have rebounded somewhat the past couple of months, as has production, suggesting that while E&Ps third-quarter results will be far from stellar, they’ll at least show an improvement and hopefully set the stage for further gains going forward. Today, we break down second-quarter results by producer peer group and discuss the positive trends that portend improved results for the third quarter.

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.

Western Canadian producers have been deeply impacted by lower crude oil prices and the demand-destroying effects of COVID-19. This past spring, oil production in the vast region dropped by an estimated 940 Mb/d, or as much as 20% from the record highs earlier this year. Taking that much production offline helped in at least one sense: it eased long-standing constraints on takeaway pipelines like Enbridge’s Canadian Mainline, TC Energy’s Keystone Pipeline, and the government of Canada’s Trans Mountain Pipeline. Production has been rebounding this summer, however, and there are indications that pipeline constraints may be returning and apportionment of uncommitted space on some pipes may again become a persistent issue. Today, we continue a review of production and takeaway capacity in Alberta and its provincial neighbors with a look at apportionment trends on the biggest pipelines.