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.

Despite the pandemic-driven economic slowdown wreaking havoc on the global LNG market, U.S. LNG export volumes from operating terminals have proven resilient, so far. Total feedgas deliveries to the liquefaction and export facilities peaked at 9.44 Bcf/d less than a month ago and are averaging about 8.3 Bcf/d in April to date. But for many of the already-struggling second wave of U.S. liquefaction projects still under development, the one-two punch of the crude oil price crash and COVID-related lockdowns has further stymied — or in some cases even reversed — their progress toward securing long-term capacity commitments and reaching final investment decisions anytime soon. Today, we provide an update on the status of the next round of prospective LNG export projects.

For most of the past three years, Western Canadian producers have had to deal with crude oil pipeline constraints — takeaway-capacity shortfalls serious enough to spur huge price discounts for the region’s benchmark Western Canadian Select (WCS) that are sufficient to support the higher cost of crude-by-rail alternatives. But things are changing, and fast. WCS prices are at or near historic lows — low enough to convince a number of producers to rein in their capital spending and production. Crude-by-rail use is down, and there’s even space available on the usually maxed-out Enbridge Mainline system, the region’s primary pipeline egress. And wouldn’t you know it, just as production is slipping and constraints are easing, real progress is being made on three big pipeline projects that had long been in limbo: the Line 3 Expansion, the Trans Mountain Expansion (TMX) and Keystone XL. Today, we provide an update on Western Canadian crude takeaway capacity and examine whether the region may — irony of ironies — end up with too much.

U.S. crude oil production is off its historic highs, the rig count is in free-fall, and crude inventories are rising fast, with the Cushing-to-Magellan East Houston price differential drawing oil away from the Gulf Coast and to the Oklahoma storage hub. Oh, and global demand for crude is off by more than 20%. None of this bodes well for U.S. crude exports, which have been at or near record levels the past few months. What seems to be shaping up is a fierce competition among the owners of existing export terminals to offer the most efficient, lowest-cost access to the water. Today, we continue our series with a look at Enterprise Products Partners’ Houston-area crude oil storage, pipelines and docks.

The Canadian natural gas market has exited the most recent heating season in reasonable shape. Storage withdrawals were below average thanks to mild winter temperatures, but overall storage levels at the end of the season were not too far out of line with the five-year average thanks to below-average storage levels in the west more than offsetting above-average storage levels in the east. However, Canadian gas storage may be facing a most unusual test this coming summer as storage injection activity will be influenced by reduced gas demand in the U.S. due to COVID-19 disruptions, as well as the potential for similar pandemic-driven weakness in homegrown demand, especially in Alberta’s gas-intensive oil sands. How the various pushes and pulls on gas flows play out this summer could very well determine if Canadian gas storage might test capacity limits this injection season. Today, we consider this possibility.

The whirlwind of events that has transpired in the past couple of months — namely the coronavirus pandemic and the collapse of the OPEC+ coalition — has not only shaken up the energy markets, but quite literally sent it reeling in the opposite direction than where it was headed just a few months ago. The oil price decline has reverberated through the energy complex, and key indicators that drive industry decisions are veering far off from their recent course, and in many cases, also from historical norms. The world is continuing to change at a rapid pace as the industry navigates the uncertainty. Just yesterday, in an emergency meeting, OPEC announced it had reached a 23-nation agreement to cut a combined 9.7 MMb/d of crude oil production starting May 1, 2020. Today, we highlight some of the biggest moves happening in prices and price relationships in recent days and weeks as the realities of crude oil demand constraints, supply glut and low prices set in.

The U.S. natural gas market has been on edge as it awaits more clarity on the extent of the demand destruction that could transpire, both from COVID-related commercial and industrial closures and potential disruptions to U.S. LNG export activity from demand losses downstream, particularly in Europe and Asia. The CME/NYMEX Henry Hub prompt contract last week set at all-time lows for April trading — twice — before gaining ground again this week as forecasts turned decidedly more bullish for April. But the market remains under pressure, as it heads into the storage injection season with an inventory that’s well above the year-ago and five-year average levels. With the economic slowdown likely persisting, in the U.S. and globally, in the coming weeks and months, the question is, could potential demand loss send the inventory barreling toward record-high, or even capacity-testing, levels by this fall? How much demand loss would it take for that to happen? Today, we assess the potential impacts of domestic demand loss and possible LNG cargo cancellations on the U.S. gas market.

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.

The crash in global crude oil markets has meant low prices for all producers, but no place more so than in Alberta’s oil sands. Transportation, blending and quality differentials mean that benchmark Western Canadian Select (WCS) is priced at a significant discount to light, sweet West Texas Intermediate. With WTI prices seemingly stuck below $30/bbl, the absolute price of WCS last week tumbled to all-time lows below $5/bbl. If they persist, will WCS prices south of $10/bbl generate wide-scale production shut-ins in the oil sands? Today, we continue our series on the challenges facing Alberta’s oil sands.