For the past few years, demand for U.S.-sourced ethane has been on the rise as petrochemical companies in the U.S. and abroad developed new, ethane-only steam crackers and retrofitted existing crackers to allow more ethane to be used as feedstock. U.S. NGL production was increasing too, of course, alongside growth in crude oil-focused plays like the Permian and “wet” gas plays like the Marcellus/Utica. But recently, drilling-and-completion activity has slowed to a crawl and NGL production has been leveling off, which means that less of the ethane that comes out of the ground with oil and gas will be “rejected” into natural gas and more will be separated out at fractionation plants. Today, we conclude a series on ethane exports with a look at U.S. NGL production, ethane supply and demand, ethane exports, and ethane prices.
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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.
Not long ago, the economics for U.S. LNG exports were practically a no-brainer. Despite the longer voyage times and the resulting higher shipping costs from Gulf Coast and East Coast ports to Europe and Asia — by far the biggest LNG consuming regions — LNG priced at the U.S.’s Henry Hub gas benchmark presented a competitive alternative to other global LNG supply, much of which is indexed to oil prices, which were higher then. But earlier this year, as oil prices collapsed, COVID-19 lockdowns decimated worldwide gas demand, and international gas prices plummeted, the decision to lift U.S. cargoes has become much more nuanced, and the commercial agreements to support the development of new liquefaction capacity are much harder — if not impossible — to come by. Today, we discuss highlights from RBN’s latest Drill Down Report on the impact of recent market events on U.S. export demand, capacity utilization, and new project development.
In observance of today’s holiday, we’ve given our writers a break and are revisiting a recently published blog on the U.S.’s shifting role in the global LNG market. If you didn’t read it then, this is your opportunity to see what you missed! Happy Labor Day!
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.
The U.S. natural gas pipeline sector is entering a challenging period for recontracting a major chunk of its capacity. The numerous pipeline systems built during the early years of the Shale Era’s midstream boom were anchored by 10-year, firm shipper contracts, mostly with producers, making them so-called “supply-push” pipelines. Many of those initial contract periods have begun to roll off, exposing pipelines to producer-shippers’ renewal decisions based on current fundamentals. Shippers typically expect substantially lower rates for a renewal contract, because much of the pipeline has been paid off through depreciation. But there’s another issue that is becoming more important: shipper recontracting may not happen for market reasons. For pipeline owners, this is happening at the worst possible time. The market is in turmoil and facing ongoing uncertainty. Gas production is down, demand from LNG export facilities is in flux, and regional supply-demand dynamics are shifting. As if that weren’t enough, new, large-diameter pipelines out of the Permian now nearing completion will reshuffle gas flows around the country. And other transportation corridors that not long ago were bursting at the seams and feverishly expanding to ease constraints are now at risk of being underutilized. Today, we discuss the factors that together may present significant risk for pipelines approaching the proverbial recontracting “cliff.”
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.
Understanding whether propane production is up or down over the past few months is a bit more difficult than you might think, depending on which set of EIA numbers you choose to look at. The U.S. Energy Information Administration provides monthly numbers on the last day of the month lagged by about two months, and weekly numbers on Wednesdays, lagged by only five days. Both time series are closely watched by the propane market to assess the availability of supply for retail customers, petrochemical feedstock demand, and exports. Usually, these two sets of numbers move in tandem. But not always. The monthly numbers show production down by about 70 Mb/d from April to June, which is what you would expect given what was happening with crude and gas production at that point in time. Yet EIA weekly production numbers showed production increasing by about 90 Mb/d for the same period. So which way is propane production really trending? If you want to understand what’s going on, and you don’t mind delving into some deeply wonky NGL analytics, hang on for today’s blog.
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.
About two-thirds of all of the propane consumed in the U.S. is used as fuel — for indoor and outdoor cooking, home heating, water heaters, drying crops, and running forklifts and fleet vehicles. The other one-third is used as a feedstock for producing ethylene and other petchems. About 95% of the propane supply to meet this demand is produced and processed right here in the U.S. of A., making propane the most American fuel we’ve got. But when firing up the grill out back and watching that first propane molecule flash to life, most backyard chefs don’t think much about the long and winding road their propane has traveled. It’s actually a fascinating tale of supply-chain logistics that involves high pressures, bitter cold, wild rides up and down tall towers, storage deep underground, and, of course, trains, trucks, and tanks. We think it’s a tale that needs to be told, and that’s what we’ve been doing in this update of another Greatest Hit blog.
Just as U.S. LNG exports were beginning to recover from months of market-driven cargo cancellations, major Hurricane Laura has cut the rebound short. With Laura taking aim at the Texas-Louisiana border — the location of two large-scale LNG export terminals, including the U.S.’s largest export facility, Cheniere Energy’s Sabine Pass Liquefaction terminal — total feedgas flows to U.S. terminals the past two days dived to fresh lows for 2020 and the lowest since February 2019. Gas production is also way down, with offshore Gulf of Mexico production shut-ins compounding the effects of already depressed drilling and completion activity this year. But production has the potential to rebound more quickly than LNG exports, which could exacerbate the onshore demand effects of the storm; It already will bring cooler weather and drench gas demand for power generation as it moves inland over the Southeast and into the Mid-Atlantic states. Today, we look at how LNG exports are being affected by the storm and what that could mean for the overall gas market balance in the coming days.
Yet again, the Texas-Louisiana coast is bracing for a hurricane that has the potential to be really bad, not just for the people and homes in the storm’s path, but for the region’s all-important energy sector. Hurricane Laura will be crossing a swath of the Gulf of Mexico dotted with oil and gas production platforms, and is headed for an area chockablock with tank farms, refineries, and steam crackers, as well as export terminals of every stripe: crude oil, refined products, ethane, LPG, and LNG. There’s a good chance there’ll be a lot of disruption to many energy-related activities for at least the balance of this week — and maybe longer — but one of the biggest hits could come to Mont Belvieu, TX, the center of NGL storage and fractionation. Today, we discuss how the storm might affect not only storage at the U.S.’s largest NGL hub, but gas-processing activity hundreds of miles inland.
Not long ago, the economics for U.S. LNG exports were practically a no-brainer. Despite the longer voyage times and the resulting higher shipping costs from Gulf Coast and East Coast ports to Europe and Asia — by far the biggest LNG consuming regions — LNG priced at the U.S.’s Henry Hub gas benchmark presented a competitive alternative to other global LNG supply, much of which is indexed to oil prices, which were higher then. But earlier this year, as oil prices collapsed, COVID-19 lockdowns decimated worldwide gas demand, and international gas prices plummeted, the decision to lift U.S. cargoes has become much more nuanced, and the commercial agreements to support the development of new liquefaction capacity are much harder — if not impossible — to come by. Today, we discuss highlights from RBN’s latest Drill Down Report on the impact of recent market events on U.S. export demand, capacity utilization, and new project development.
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.
When you talk about energy molecules, propane takes the prize for the most versatile. In addition to its well-known uses for BBQ grills, indoor cooking, and home heating, propane is used for drying crops, as a feedstock for petrochemicals, as an engine fuel for forklifts and fleet vehicles, and in recent years, as an export product in its own right. Propane moves to market on pipelines, railcars, ships, barges, trucks — just about any form of transportation you can imagine. But exactly how any particular molecule of propane makes the journey from the instant it comes out of a well to all those market destinations can be a mystery to all but a small cadre of propane market insiders. In another in our series of updates to RBN’s greatest hit blogs, we are delving into this mystery, one step at a time, today focusing on transportation from the producing basin to storage and fractionation at the Mont Belvieu hub, and the transformation of the generic commodity to a marketable fuel.
Bakken associated gas production volume, after falling to its lowest levels in three years in early May and remaining depressed through June, has surged by 500 MMcf/d, or about 45%, in the past month and a half to 1.7 Bcf/d. However, the gains have occurred in the absence of a meaningful change in rig counts or well completion activity, which remains sluggish. Similar to the Permian, the Bakken production recovery has been almost entirely driven by existing wells returning to service after being shut in earlier this year in response to the oil price collapse. With little in the way of new drilling and completion activity, how long will it be before natural declines of existing wells begin to take a toll on Bakken output? Today, we examine prospects for continued strength in Bakken gas production volumes.