Most Popular Blogs of 2020

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.

Natural gas economic shut-ins! Shutting off a producing well on purpose, because the market won’t take the produced volume at a reasonable price. There was a time, back before gas commodity decontrol, when shut-ins were standard operating procedure, but that practice went the way of the dodo bird 40 years ago. Until earlier this year that is, when amid crushingly low prices, Appalachian producers said: enough is enough — and shut off the spigot themselves. In the months that followed, various producers have continued to see-saw their production in response to weather-related demand and regional market prices. The behavior signals that Appalachia’s shale gas producers are increasingly employing a light-switch approach in dealing with short-term weakness in demand and prices. Today, we take a closer look at the price-driven curtailments in the Northeast and potential implications for the market.

Everywhere you look these days, someone is talking about hydrogen and, if you’re not well-versed in emerging technologies aimed at reducing carbon, you may not know what any of it means. A quick internet search isn’t much help either, as you will likely get lost quickly in discussions of fuel cell efficiency and electrolysis technology developments, not to mention the various “colors” of hydrogen and the myriad of ways it can be stored and transported. Don’t bother turning to your traditional green energy gurus either, as hydrogen is just one of many competing approaches to reducing the world’s carbon footprint, and electric vehicle folks like Elon Musk aren’t big fans. All the same, hydrogen news and investment plans seem to proliferate daily, and understanding this fuel — which, by the way, is not new to the energy space — seems prudent. At least that’s our view, which is why we today start a series to help us hydrocarbon experts unravel the mysteries behind the recent hydrogen ruckus.

Permian natural gas production is now expected to grow at a subdued pace over the next five years, as lower oil prices and a focus on capital discipline have slashed rig counts. Few observers see the Permian situation changing anytime soon, especially as crude oil prices continue to hover around $40/bbl. That said, the Permian gas market will be anything but dull over the months and years ahead. More than 4 Bcf/d of new outbound pipeline capacity from the Permian to the Gulf Coast will be coming online next year, throwing natural gas flows from West Texas into flux and deeply impacting neighboring markets. While natural gas basis at the Permian’s primary Waha hub should improve dramatically, outflow to the Midcontinent will likely fall sharply and potentially reverse, and the Texas Gulf Coast will see an influx of supply on the new pipelines. Today, we continue a series that highlights findings from RBN’s new, Special Edition Multi-Client Market Study.

Propane exports from AltaGas and Vopak’s Ridley Island Propane Export Terminal on the west coast of British Columbia jumped to 52 Mb/d in May, the highest since it began operations in May 2019 and exceeding the terminal’s original design capacity for the second time this year. The increased exports suggest expanded capacity at the facility and the potential for sustained higher exports from there even as Western Canada’s propane supplies plateaued in 2019 and then were hammered lower earlier this year as oil prices and demand collapsed. The resulting tighter balance in the greater Pacific Northwest region has boosted prices there, wreaking havoc on price spreads and disrupting rail movements to U.S. destinations that have relied on them for the past few years, from the Midwest to California. Moreover, Western Canadian export capacity is poised to nearly double by next spring, when a second nearby export terminal is slated to begin operations. With supply upside looking tenuous, but overseas exports set to rise further in early 2021, there is a serious squeeze emerging for propane rail exports to the U.S. Today, we consider the implications of what could be a much tighter propane market in Western Canada over the next few years.

Crude oil supply news comes in from all angles these days, bombarding the market daily with fresh information on producers’ efforts to ramp their volumes back up now that the global economic recovery is cautiously under way. Crude demand is rising, storage hasn’t burst at the seams yet, and prices have come a long, long way in just a few weeks. Permian exploration and production companies, having avoided a fleeting, longshot chance that the state of Texas might regulate West Texas oil production, are responding to higher crude oil prices as free-market participants should. The taps are quickly being turned back on, unleashing pent-up crude and associated gas volumes that, you could say, were under a sort of quarantine of their own for a while. Today, we provide an update on the status of curtailments in the Permian Basin.

With a dwindling market for their crude, many U.S. producers are confronting an unavoidable choice: shutting in existing production. Just go out and flip a switch and turn a valve, right? Wrong. Like everything else in the COVID era, shutting in production is complicated. It is the alternative of last resort for producers, whose primary directive is the economic extraction of oil and gas. But with demand for their products crushed, production from some wells no longer makes economic sense. Unfortunately, the process of shutting in wells is charged with contractual, economic and operational issues that the industry is scrambling to deal with. The situation is fraught with uncertainty, and many producers’ futures depend on how decisively they manage the shut-in process. Today, we discuss the urgent need to reduce oil production and the judgments producers will be making as they take wells offline.

On Monday, front-month WTI at Cushing cratered to a negative $37.63/bbl. On Tuesday, the same futures price rose by nearly $48 to close at about $10/bbl — a positive $10, that is. As for WTI to be delivered in June, it lost well over a third of its value on Tuesday, ending up at less than $12/bbl, but over the past two days it has roared back to over $16/bbl. No doubt the WTI futures market will see more wild times in the days and weeks ahead as traders look to avoid the traps that ensnared the market as the May contract approached expiry. If there’s a lesson to be learned from the past week, it’s that it really helps to understand the ins and outs of the futures market — especially when it is so volatile. Perhaps the most important thing to wrap your head around is that while the futures market mostly involves financial players who will never take physical delivery of oil, the two markets — financial and physical — are fundamentally linked. Prompt-month futures converge on spot prices over time, while physical contracts are settled in part based on NYMEX futures, so producers will feel the sting of Monday’s negative prices when physical April deliveries are invoiced. Today, we begin a two-part blog series examining U.S. spot crude pricing mechanisms.

Sharply declining refinery demand for crude oil was a key driver in the historic collapse in near-term futures prices for WTI at Cushing earlier this week. With stay-at-home directives in place in most of the industrialized world, U.S. — and global — demand for motor gasoline and jet fuel has plummeted to levels not seen in decades. These changes in refined-products demand, which may continue for months, already are having significant impacts on U.S. refineries — not just in how much crude oil they need but in operators’ decisions on whether to adjust their crude slates and ramp down or alter their operations. Their urgent challenge is to revise their yields to something close to the appropriate volumes of gasoline, diesel and jet fuel. Today, we begin a blog series on the U.S. refining sector and what refiners can — and can’t — do to adapt to these extraordinary times.

Underlying Monday’s financially driven oil price rout are physical markets that are in extreme turmoil as they contend with severely reduced demand resulting from the COVID lockdowns and rapidly filling storage tanks. In the Permian Basin, the epicenter of U.S. shale oil, the crude benchmark price — WTI at Midland — on Monday crashed to a historical low of negative $13.13/bbl before rebounding to a positive $13.01/bbl Tuesday. The same day, prices at the Permian natural gas benchmark Waha revisited negative territory for the third time this month, with a settle of minus $4.74/MMBtu for Tuesday’s gas day. Negative supply prices aren’t new to Permian producers, at least for gas — Waha settled as low as minus-$5.75/MMBtu in early April 2019. But up until a couple months ago, oil prices were supportive enough to keep producers drilling regardless. Now, that’s all over, at least for a while. What can we expect now that negative oil prices have arrived in the Permian? Today, we’ll dissect the latest bizarre pricing event to rattle the Permian natural gas and oil markets.

We have now entered the crude oil twilight zone.  Never before has crude traded below zero, much less at the absurd level of negative $37.63/bbl.  There is no doubt that demand for crude and motor gasoline are far below crude production volumes, leaving the market vastly oversupplied.  But could it really be this bad?  When you are talking about the market for physical barrels, the answer is “no”.  It is bad.  Really bad. But what happened yesterday had more to do with the mechanics of futures contracts and how they transition from month to month, than a complete mega-meltdown in physical barrels.  That is not to say that negative prices for physical barrels are not already a fact of life in some locations. But negative $37.63/bbl?  Something else must be going on. So, to put yesterday’s bizarre market action in perspective, we need to get into a few details on futures contract mechanics, and then look forward to what may be coming over the next few weeks.  In today’s blog, we discuss the factors that are driving such extraordinary crude market developments.

In an energy market filled with incalculable uncertainty, it is no surprise that most of the focus is on the short term: production shut-ins, collapsing demand, refinery unit shutdowns, ballooning storage inventories and continually weakening prices. But even in the face of such dire circumstances in the weeks just ahead, there remains a cautious optimism — relatively speaking — for the resumption of some kind of new normal on the other side of COVID. You can see that expectation in the numbers, with the WTI May 2020 contract settling on Friday at $18.27/bbl, but the May 2021 contract up to $35.52/bbl. Granted, that May 2021 price would have been catastrophic if viewed in January 2020, but now it’s a bullish 95% increase over the front month.  It is that shift in perspective that underlies the fundamentals content that we developed for our two-day Spring 2020 Virtual School of Energy, held last week in the cloud: how things were viewed BEFORE the meltdown, and how things look AFTER — over the next five years. Did you miss the conference? Not to worry. The entire 14 hours of content are available online in our encore edition. It’s almost like being there! Today’s advertorial blog reviews some of the most important findings we covered at School of Energy and summarizes our overall virtual conference curriculum.

E&Ps have long been accustomed to negative investor sentiment and the depressed stock valuations that come with it. But who among them could have anticipated the first quarter’s devastating one-two punch of coronavirus-related energy demand destruction and the collapse of the OPEC+ supply-management effort that for more than three years had propped up crude oil prices? E&Ps responded by slashing their 2020 capital spending plans and touting how much of their 2020 production is hedged. But there’s no doubt about it, the E&P sector is in for particularly hard times, as evidenced by Whiting Petroleum’s Chapter 11 filing last week. A major impediment for Whiting and other already hobbled E&Ps is a cost structure that, for many, significantly exceeds the current price of oil. Today, we discuss what an examination of more than 30 E&Ps’ lifting, DD&A and other costs reveals about the companies’ ability to stay afloat in rough seas.

Like everything else in the world, energy markets are undergoing totally unprecedented convulsions. It seems as if everything that was working before COVID-19 is now broken, and an entirely new rulebook has been thrust upon us. Of course, it is impossible to know how crude oil, natural gas and NGL markets will play out over the next few weeks, much less in the coming years. But if we make a few reasonable assumptions, extrapolate from what we know so far, and crunch through a bit of fundamental analysis, it is possible to imagine what energy markets will look like after the worst of the coronavirus pandemic is behind us. One thing is for sure: things will not be anything like they were before. Where energy markets may be headed next is what we will conjure up in today’s blog.

On Friday, global energy markets entered uncharted territory. Already facing declining demand due to the impact of COVID-19, markets then were dealt a body blow with the collapse of the OPEC-Plus alliance and the resulting prospect of a significant increase in supply. Saudi Arabia wanted to manage supply to balance against lower demand, but Russia was having none of it. Instead, reports from the OPEC-Plus meeting indicate that Vladimir Putin has declared war on U.S. shale. Then on Saturday, the plot thickened. Saudi Arabia made huge cuts in the price of its crude oil, presumably in a high-stakes move to bring Russia back to the negotiating table. Even though we are witnessing unprecedented market conditions, it’s not Armageddon. Crude oil will continue to be pumped, piped, shipped and refined. Most infrastructure projects under construction before the collapse in oil prices will be completed. The big question is, how will the market adapt? In today’s blog, we’ll begin an exploration of that question.