Things move fast in today’s propane market. Two weeks ago, Mont Belvieu propane was going for almost 95 cents/gal, up 86% from the mid-November price of only 51 c/gal. Midcontinent propane assessed in Conway, KS, spiked even higher, doubling over the same time frame to more than a dollar per gallon. But last week some air came out of the balloon, with Mont Belvieu and Conway prices pulling back to the low 80s. That didn’t last long either. This week, Mont Belvieu is back up to the high 80s c/gal. What gives? Is the market simply being bounced around by vacillating weather forecasts? Or is there more to it than that? Could it be that we are seeing symptoms of an export-driven transformation that is making propane markets behave quite different than they have in the past? Today, we’ll consider these questions and where the propane market may be headed in 2021 and beyond.
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Daily energy Posts
As the year 2020 wears on, it seems that every month brings a new surprise. In August, in addition to the ongoing pandemic and protests, a major hurricane was added to the mix. What comes next is anybody’s guess. A zombie apocalypse? An alien invasion? At this point, the possibilities seem boundless. And the energy industry has been no stranger to this year’s turmoil, what with COVID-related demand destruction, an oil-price collapse, and production shut-ins. Amidst the chaos, the Department of Energy (DOE) announced that for the first time, private-sector energy companies would be allowed to store crude oil in the U.S.’s Strategic Petroleum Reserve (SPR), which resulted in the leasing of 23 MMbbl of capacity. Recently, those volumes have begun to be drawn back out. Today, we examine the factors influencing movements of crude oil into and out of the U.S. SPR.
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.
Yup. Pigs are critical to the safety and integrity of pipelines. Some are your basic utilitarian pigs, while others are quite smart, if not downright cool. No, these are not the pigs down on the farm. Instead, these pigs are devices run through pipes to clean, inspect, and support “batching” on hydrocarbon pipeline networks. They help ensure the safe and efficient transportation of crude oil, NGLs, petroleum products, and natural gas through more than 2.5 million miles of pipeline in the U.S. If you’re interested in energy and energy delivery, you’ve gotta know about pigs, and that's just what we'll be discussing in today’s blog.
Pipelines are lifelines to refineries, steam crackers, and other consumers of energy commodities, and even the hint that a major pipeline may be shut down raises big-time concerns. For evidence, look no further than Enbridge’s Line 5, which batches light crude oil and a propane/normal-butane mix across Michigan’s upper and lower peninsulas and to points beyond. One of Line 5’s two pipes under the Straits of Mackinac is temporarily out of service, halving the 540-Mb/d pipeline’s throughput, and Michigan’s attorney general continues to pursue a lawsuit that, if successful, could be Line 5’s death knell. Enbridge also is facing a fight on its plan to replace the twin underwater pipes with a new, safer “tunnel” alternative. All of which raises the question, what would be the market effects if Line 5 is permanently closed? Today, we conclude a miniseries on one of the Upper Midwest’s most important liquids pipelines.
In May of this year, Western Canada’s oil production shut-ins due to weak demand and poor pricing were estimated to have peaked near 1 MMb/d, resulting in a 20% drop from the near-record production levels reached only a few months earlier. The magnitude of the production fall in such a short period of time caused a significant drop in the utilization of pipelines that transport crude oil from Alberta to other parts of Canada and the U.S. All of a sudden, pipelines that had been heavily rationing their capacity over the past couple of years to accommodate steadily rising production suddenly had ample spare capacity. With those supplies now on the road to recovery, pipelines have begun to fill some of that extra space and are moving toward rationing capacity once again. Today, we continue our review of Western Canadian production and takeaway capacity with a look at how this spring’s production cuts affected the region’s biggest pipelines.
The Dakota Access Pipeline isn’t the only interstate liquids pipe facing an uncertain future. The fate of Enbridge’s Line 5, which batches either light crude oil or a propane/butanes mix from Superior, WI, through Michigan and into Ontario, also hangs in the balance as the company renews its battle with Michigan’s top elected officials to keep the 67-year-old pipeline open and its effort win regulatory approval to replace the pipe’s most important water crossing. Line 5 supporters say that closing the 540-Mb/d pipeline would slash supplies to residential and commercial propane consumers in the Great Lakes State, steam crackers in Ontario, and refineries and gasoline blenders in three states and two Canadian provinces. Critics of Line 5 counter that there are plenty of supply alternatives. Today we discuss the pipeline, what it transports, and who it serves, as well as challenges it faces.
The oil price meltdown earlier this year and demand destruction wrought by COVID-19 forced Canadian crude oil producers to throttle back output. At the height of the cutbacks in May, almost 1 MMb/d of oil supply had been curtailed due to uneconomic prices and/or lack of downstream demand. With oil prices and demand having staged a partial recovery in the past few months, production is rising off the lows and producers are talking about even higher supplies in the months ahead, with the prospect of returning to pre-pandemic levels. Today, we begin a short series that reviews the recent production pullback and discusses how producers are positioning themselves for a resurgence of their oil supplies.
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.