For U.S. refineries, the severe demand destruction that occurred this spring led to the worst financial performance in recent history. Not only did refiners produce less diesel, motor gasoline, and jet fuel in the second quarter than any quarter in recent memory, their refining margins were sharply lower than the historical range — a one-two punch that hit their bottom lines hard. The situation has improved somewhat this summer, but it’s still tough out there. So tough, in fact, that it’s reasonable to ask, does the coronavirus and its impacts to the energy sector signal the end of an era for refiners across the U.S.? Today, we review the decline in fuel demand and profitability in the second quarter and discuss the uncertainties refiners face in the second half of 2020 and beyond.
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Daily energy Posts
It’s only August, but the folks involved in Permian markets must feel like they’ve already packed in a full year’s worth of action. The events are well known by now, but they’re still remarkable. A crash in refining utilization, followed by massive field shut-ins, all precipitated by a novel virus and exacerbated by some unusual moves by global oil producers. The year’s not over, and the coronavirus hasn’t gone away like a miracle, but a calm has emerged in oil prices that has helped producers get their sea legs. While $40/bbl West Texas Intermediate (WTI) is a far cry from where we started 2020, it’s been just enough to get most of the shut-in crude production back online in West Texas. Today, we provide an update on the status of curtailments in the Permian Basin.
The collapse in crude oil prices this year hit U.S. producers hard, and forced them to make big cuts in their capital budgets and drilling plans. But it also helped to prove their resilience. Throughout the Shale Era, and especially since the 2014-15 oil price crash, producers have been increasing their productivity and slashing their production costs, enabling most of them to survive even when prices slipped below $30 and $20/bbl for a while. Not all producers are alike, however — neither is all production. Even with oil prices rebounding to about $40/bbl in recent weeks, production based on enhanced oil recovery (EOR) through carbon-dioxide (CO2) “flooding” has become economically challenged, at least for some producers. Can EOR, with its high production costs, survive in a low-price environment? Today, we take a fresh look at EOR in an era of $40/bbl crude.
The COVID-19 pandemic has undone a number of long-standing energy-market expectations. Just a few months ago, U.S. crude oil production was hitting new heights, export volumes were rising fast, and producers, shippers, and others were worried whether there would be sufficient marine-terminal capacity in place. Now, crude production is down sharply, and while crude exports have held up during this year’s market turmoil, the old belief that exports would keep rising through the early 2020s is out the window. Where does that change in expectations leave all those crude export terminals along the Gulf Coast, many of which were recently built or expanded to help handle the flood of crude that was supposed to be heading their way? Today, we discuss highlights from RBN’s new Drill Down Report on crude-handling marine facilities along the Texas and Louisiana coast.
As the number of new COVID-19 cases continues to rise, so does the oil patch’s apprehension that crude oil prices could be poised to take another hit. If that happens, producers would have to review, yet again, their plans for optimizing production as best they can, given their pricing outlook. But producers do not all receive uniform prices reflecting NYMEX WTI for their physical barrels — far from it. Crude quality and proximity to a demand market can make a big difference in the price that the barrels will ultimately sell for. Price reporting agencies (PRAs) such as Argus and Platts track and publish these differentials. But how are those differentials calculated and how do they affect producers? Today, we discuss crude differentials and their impact.
Associated natural gas production out of the Permian Basin rebounded sharply a few weeks ago, indicating production curtailments that went into effect in May in response to low crude oil prices are coming back online. Just as abruptly as gas production dived in early May, it lurched upward in late June, nearly back to where it was before the shut-ins began. But the rig count has continued falling to a record low, and indications are that many of the wells drilled over the past few weeks have not been completed. The meager drilling and completion activity suggests that the natural declines of existing wells, which were temporarily exaggerated by the shut-ins, will now be felt — and felt for as long as rig counts remain depressed — not just in the Permian but also in other oil-focused basins. Daily gas production volumes in the Permian in the past 10 days or so already are slipping, despite shut-ins tapering. Today, we examine the latest production trends in the Permian and what it will mean for the gas production outlook.
For almost a year now, Corpus Christi-area marine terminals have been exporting more crude oil than their competitors in Houston, Beaumont, and Louisiana, largely thanks to the recent startup of new, large-diameter oil pipelines from the Permian to Corpus. Beginning today, with the expected arrival of the first tanker at the spanking-new South Texas Gateway Terminal in Ingleside, the Corpus area will have the potential to widen its lead in export volumes. In addition to its connections to the EPIC Crude and Gray Oak pipelines from West Texas — and the new Harvest Pipeline and the older Flint Hills Resources system — the South Texas Gateway facility can partially load 2-MMbbl Very Large Crude Carriers. Today, we discuss the Gulf Coast’s newest marine terminal and the important economic edge it gains from handling VLCCs.
The crude oil market may be approaching another rough patch, with the trajectory of the COVID pandemic and OPEC+ again poised to inflict a double whammy on U.S. producers. For the past couple of months, refinery demand for crude has been rebounding as the U.S. has made tentative steps toward reopening. Over the same period, domestic production of oil declined and then flattened out, and now appears to be headed for a midsummer uptick as more shut-in wells are brought back online. But there’s potential trouble just ahead. The months-long imbalance between crude supply and demand boosted U.S. oil inventories in commercial storage to record-high levels over the past few weeks, with even more oil flowing into rented space in the Strategic Petroleum Reserve (SPR) salt caverns. Worse yet for producers, a resurgence of the coronavirus may put some parts of the U.S. back into semi-lockdown, and if that happens, refinery utilization could take a second tumble. That could push more crude into storage or onto supertankers for export, even as OPEC+ is talking about relaxing their production cuts. Today, we examine the trends that could be problematic for U.S. oil producers and refiners in the second half of 2020 and beyond.
A federal judge’s order that the 570-Mb/d Dakota Access Pipeline be taken out of service for a year or more starting August 5 has the potential to wreak more havoc for producers in the Bakken Shale at a time when they are still reeling from drastic, COVID-related production curtailments. While those production cuts have opened up at least some capacity on other takeaway pipelines out of western North Dakota and crude-by-rail terminals may be able to ramp up their operations, that may not be enough to make up for the loss of DAPL — still more well shut-ins may be required. Then there’s the matter of taking the 1,172-mile, 30-inch-diameter pipeline offline in only four weeks’ time — it involves much more than flipping a switch and may not even be possible within that time frame. Today, we consider the hurdles and implications of removing DAPL from service.
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.
Producers in Alberta’s oil sands have been through good times and bad times the past few years. Sure, there’s been a lot of growth in output since 2010. But they’ve also seen wildfires that forced one-third of production offline. And pipeline takeaway constraints that sent prices tumbling and spurred government-imposed production cutbacks. And lately, they’ve been struggling through a global pandemic that slashed crude-oil demand and led to further curtailments. Despite it all, producers and the province of Alberta are hopeful about an oil sands rebound, and shippers are optimistic that they can source an increasing share of the diluent they would need to transport bitumen from Western Canada. There’s good news on that front: there appears to be plenty of diluent pipeline capacity already in place between Alberta’s diluent hubs and its oil sands production areas. Today, we continue our series by exploring the major pipeline systems that distribute diluent supply to the oil sands.
The folks who transport bitumen from the Alberta oil sands to faraway markets depend on light hydrocarbons collectively known as diluent to help make highly viscous bitumen flowable enough to be run through pipelines or loaded into rail tank cars. The catch is — or was, we should say — that Western Canada wasn’t producing nearly enough condensate and other diluent to keep pace with fast-rising demand, so a few years ago, two pipelines from Alberta to the U.S. Midwest were repurposed to allow diluent to be piped north. More recently, though, Western Canadian production of diluent has been soaring and new pipeline capacity has been built within Alberta to deliver it to the oil sands. That has the potential to reduce the need for imports from the U.S. and may soon lead to at least one of the import pipes being repurposed yet again. Today, we continue our series on diluent with a review of the pipeline systems that collect locally produced light hydrocarbons that are eventually employed in the oil sands.
Enbridge’s proposal to have crude oil shippers on its now fully uncommitted Mainline sign long-term contracts for as much as 90% of the 2.9-MMb/d pipeline network’s capacity is a big deal — and controversial. Refiners and integrated producer/refiners generally support the plan, which is now up for consideration by the Canada Energy Regulator, while Western Canadian producers with no refining operations of their own — and, for many, no history of shipping on the Mainline — mostly oppose it. What’s driving their contrasting views? It’s complicated, of course, but what it really comes down to is that everyone wants to avoid what they see as a bad outcome. Refiners and “integrateds” fear that if the current month-to-month approach to pipeline space allocation remains in place, cost-of-service-based tariffs on Mainline will soar when new takeaway capacity is built on the Trans Mountain and Keystone systems and fewer barrels flow on Mainline. Producers, in turn, are wary of making multi-year, take-or-pay commitments to Enbridge if they’ll soon have other takeaway options, and are equally concerned that they’d be left in the lurch if they don’t commit to Mainline and the Trans Mountain Expansion and Keystone XL projects don’t get built. Today, we consider both sides of this important debate.
Since last summer, the Corpus Christi area has emerged as the U.S.’s leading crude export venue. In the first five and a half months of 2020, it accounted for an astounding 45% of the barrels being shipped abroad — astounding because in the same period last year, the Corpus area held less than a 20% share. What is sometimes forgotten, though, is that little Ingleside, TX, located across Corpus Christi Bay from Corpus proper, is the area’s crude-export leader, with the Moda Midstream and Flint Hills Resources terminals responsible for just over half of Greater Corpus’s total export volumes. And, with the new South Texas Gateway Terminal nearing completion, Ingleside’s role will only increase in the coming months. Today, we conclude a series on Gulf Coast export terminals with a look at what has been going on in Ingleside.
Brent is by far the most important crude oil benchmark in the world, with well over 70% of all global crudes tied either directly or indirectly to the North Sea crude’s price. But the original Brent crude oil production is almost played out, with all of the offshore Brent producing platforms soon to be decommissioned. This might seem to be a big problem, but in the world of crude oil trading, it is a total non-issue, because Brent is no longer simply a grade of crude oil. It is a multi-layered matrix of trading instruments, pricing benchmarks, and standard contracts linked together by price differentials traded across a number of mechanisms and platforms that form the foundation of a robust, vibrant, and extremely important marketplace. Today, we delve further into the mechanics of the Brent complex, the key components that make it work, and the transactional glue that binds them together.
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.