So far, 2020 has been another bad year for bitumen producers in Alberta’s oil sands. For the second year in a row, they have been forced to endure production curtailments, this time in response to COVID impacts on demand and the resulting record-low heavy oil prices. Still, there are at least glimmers of hope that the bitumen market will soon enter at least a modest recovery mode, and that further gains will be possible in 2021 and beyond. Moving all of that bitumen to market in pipelines and in rail cars is going to require even more diluent than the record amounts already consumed in late 2019 and early 2020. Today, we consider the outlook for bitumen production, what that outlook means for future diluent demand, and if that demand can — or cannot — be met by the various sources of diluent supply.
Daily energy Posts
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.
Energy markets are changing faster than at any time in history. It’s hard enough just to keep up with what’s happening today, much less try to anticipate what’s ahead on the other side of COVID. But that’s exactly what we’ll be doing next week at RBN’s Virtual School of Energy. More than one-third of the curriculum is a detailed review of RBN’s hot-off-the-presses forecasts for all the essential elements of U.S. crude oil, natural gas and NGL markets, including our freshly updated outlooks for production, infrastructure utilization, exports/imports and demand. Better yet, we’ll put these forecasts in the context of our fundamental analysis and models, so you can not only understand where it looks like we’re headed today, but gain the skills to adjust your outlook on the fly as circumstances change. Although this blog is an advertorial, stick with us if you would like to know more about how the RBN crystal ball works.
Just a few months ago, crude oil producers and marketers were wondering whether there would be enough marine terminal capacity along the Gulf Coast to handle the steadily increasing volumes of crude that would need to be exported over the next few years. Now, with WTI prices hovering around $25/bbl and producers slashing their 2020 drilling plans, expectations of rising U.S. production and exports are out the window. Instead, what may be shaping up is a fierce competition among the owners of existing storage facilities and loading docks to offer the most efficient, lowest-cost access to the water. Today, we continue our series with a look at two large Houston-area facilities: the Houston Fuel Oil Terminal and Seabrook Logistics Marine Terminal.
If Saudi Arabia and Russia flood the world with their crude oil in the midst of a global demand crisis, it would have impacts and implications far beyond crude. A ramp-up in Saudi and Russian oil production this spring would also increase their output of associated gas and NGLs. At the same time, the opposite will be happening in the Permian and other liquids-rich U.S. shale plays, where producers, stunned by sub-$25/bbl oil prices, already are pulling back on drilling and later this year will see their oil and NGL production gradually level off and eventually decline. All this is already turning the international LPG market on its head — just last week, U.S. propane exports plummeted by nearly 40% versus the prior week, to only 889 Mb/d. Today, we consider recent extraordinary market developments and their effect on the arb between Mont Belvieu and Far East LPG prices.
The collapse in WTI prices in March has been a crushing blow to the Permian, the Bakken and other U.S. shale plays that produce light, sweet crude oil. But as bad as sub-$25/bbl WTI prices are — especially for producers whose balance-of-2020 volumes aren’t at least partly hedged at higher prices — consider the record-low, $5/bbl prices facing oil sands producers up north in Alberta. Western Canadian Select, the energy-rich region’s benchmark heavy-crude blend, fell below $10/bbl more than a week ago, and on Tuesday WCS closed at $5.08/bbl. Producers, who already had been dealing with major takeaway constraints, are ratcheting back their output and planned 2020 capex, and slashing the volumes they send out via rail in tank cars. Today, we begin a short blog series on the latest round of bad news hitting Western Canada’s oil patch.
While the crude oil market meltdown has taken center stage in recent weeks, and for good reason, the natural gas market is bracing for its own fallout. The CME/NYMEX Henry Hub April futures price, which was already at a multi-year low, buckled last week, falling to as low as $1.602/MMBtu on March 23, and expired Friday at $1.634/MMBtu, the lowest April expiration settle since 1995. On its first day in prompt position, the May futures contract yesterday eked out a late-day, 1.9-cent gain that brought it back up near $1.70/MMBtu as traders continued weighing competing market factors. Gas futures earlier in March were initially buoyed by the assumption that the low oil-price environment would slow associated gas production — and it will, eventually. But that initial bullish sentiment was quickly usurped by the more immediate effects of demand losses resulting from the economic slowdown caused by COVID-19, as well as from mild weather. Today, we look at how these developments are shaping gas supply-demand fundamentals heading into the gas storage injection season.
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.
The collapse in crude oil prices and subsequent cuts in producers’ planned 2020 capital spending make it crystal clear that drilling activity in the Bakken will be slowing. Still, even with less drilling, it will take at least a few months for crude production in the North Dakota shale play to fall by much, and Bakken producers will continue to depend on crude gathering systems to give their wells the most efficient, cost-effective access to takeaway pipelines and crude-by-rail terminals. Longer term, it’s important to remember that sweet spots in the Bakken’s four-county core have some of the best rock outside the Permian. Today, we continue our series with a look at another leading midstreamer’s existing and planned gathering systems, as well as its joint-venture central delivery point, shuttle pipeline and crude-by-rail facility.
The collapse in crude oil prices has sent shock waves throughout the global energy industry and Canada has been no exception. Sorting through all the impacts will take time, but what’s clear is that any earlier optimism surrounding supply growth in Canada has evaporated, including for propane supply to feed the new propane export terminals on British Columbia’s coastline. Edmonton propane prices fell 58% since the start of March to as low as 10.25 cents per gallon in U.S. dollars on March 23 — the lowest level since April 2016 — and settled yesterday at 13.13 cents per gallon, according to data from our friends at OPIS. A dampened supply outlook means future export expansion plans also are being reconsidered. Today, we explore what the sharp decline in propane prices could mean for the region’s supplies and future propane exports, including from Pembina Pipeline’s nearly completed export terminal in Prince Rupert, BC.
In the stormiest market environment for crude oil in many years, it’s hard to find a spot where the sailing is smooth. If even-keel conditions exist anywhere in the oil-producing world today, it might be the offshore Gulf of Mexico, where producer decisions to invest in new platforms or subsea tiebacks are based on very long-term oil-price expectations and the production, once initiated, is steady. In the second half of the 2010s, Gulf producers significantly reduced the average breakeven prices needed to justify their most promising new investments — from more than $55/bbl back in 2015 to less than $35/bbl today. Given what’s happened to crude oil prices the past few days, however, it’s logical to wonder whether any of even the best prospective Gulf of Mexico projects will be sanctioned this year. Today, we discuss how cost-cutting and efficiency improvements have made the offshore Gulf a comparatively steady, growing base of U.S. crude oil production that so far has been less vulnerable than shale output to oil-price gyrations.
The collapse in crude oil prices and COVID-19’s very negative effects on global gasoline, jet fuel and diesel demand are putting an unprecedented squeeze on U.S. refiners. Even before the initial coronavirus outbreak in Wuhan, China, started to grab headlines around New Year’s Day, refineries had already been incentivized to shift their refined products output toward diesel, which can be used to help make IMO 2020-compliant low-sulfur bunker. Now, with the COVID-19 pandemic spreading to Europe and North America and stifling consumer transportation fuel demand, the price signals are even stronger, pushing refineries to do everything they can to minimize their gasoline and jet fuel production and enter what you might call “max diesel mode.” Today, we discuss how there are challenges and limits to what they can do, and a number of refineries may need to shut down due to lower demand, at least temporarily.
Statewide shelter-in-place orders, worldwide business shutdowns, market meltdowns, medical calamities. Much of what is going on right now is unprecedented in the modern era, and there are no guideposts to help predict what happens next to the world as we knew it. But in the boom-bust energy sector, it is déjà vu all over again. We have seen steep drops in prices, drilling activity and production enough times to have some idea about how this is likely to play out. Granted, this time around it is particularly bad, but that doesn’t change the sequence of events that we are likely to experience over the coming months and years. Today, we’ll look back at what happens to Shale-Era basins after a price collapse, focusing on the inherent lag between a major reduction in activity level and the inevitable production response.