U.S. Northeast natural gas producers may be on the other side of a years-long battle with perpetual pipeline constraints and oversupply conditions. But they’re now facing new challenges to supply growth, at least in the near-term, from low crude oil and gas prices and the decline of a major downstream consumer of Appalachian gas supplies: LNG exports along the Gulf Coast. Most of the U.S. well shut-ins since the recent oil price collapse are concentrated in oil-focused shale plays, and gas volumes associated with those wells will be the hardest hit. However, a number of gas-focused Marcellus/Utica producers also have announced or escalated supply curtailments in recent weeks, as they wait for associated gas declines to buoy prices enough to support drilling. The pullback has had immediate effects on the region’s production volumes and supply-demand balance. Today, we provide an update on the latest Appalachia gas supply trends using daily gas pipeline flow data.
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Daily energy Posts
The Marcellus/Utica production region in the northeastern U.S. is not immune to the upheaval in global energy markets. There, a number of E&Ps are implementing further cutbacks in their natural gas production. That will result in lower NGL production, which may have serious implications for regional supplies of propane for heating this coming winter. LPG exports out of the Marcus Hook terminal near Philadelphia also may be impacted. Today, we look at recent developments in the Marcellus/Utica and the potential effects of lower NGL production in the region.
During the last two weeks of April, a barrel of propane in Mont Belvieu was more expensive than a barrel of WTI crude oil in Cushing. That’s never happened before. You might think that such an aberration could be blamed on the wacky April-May 2020 COVID crude market, but that is only part of the story. Propane production is falling and pre-COVID projections of continued supply growth are out the window. But new gas processing plants, pipelines, fractionation facilities, dock capacity and downstream demand have come online in recent years, in anticipation of those ill-fated additional supplies. Already we are seeing flows, price relationships and differentials convulsing in response to the new reality, and projections of future supply/demand imbalances suggest a previously unthinkable possibility: a market that can’t get enough propane supply, especially if the winter of 2020-21 is a cold one. In today’s blog, we will explore the evidence of these market developments that is already visible and look to what may be ahead for propane supply and demand.
The crude oil market garners all the headlines in the COVID/OPEC+ era, and understandably so. But the NGL market is also in turmoil and deserves attention too. Declining volumes of associated gas from crude-focused plays will soon be cutting into NGL supplies. Demand for natural gasoline has been hit hard, along with the crude, motor gasoline and jet fuel markets. But propane prices relative to crude oil have soared to historically high ratios, in part reflecting recent strong international demand for U.S. LPG exports. As for ethane — the lightest NGL, and the most important feedstock for the Gulf Coast petchem sector — it is going through wrenching changes, with major implications for both suppliers and steam crackers. Today, we begin a short series on the major dislocations that crude-market chaos is spurring in NGL production, ethane rejection, feedstock selection by steam crackers, and ethane/LPG exports.
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 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.
Canada has been facing a similar situation to the U.S. in recent years in which the production of natural gas liquids, such as propane, has been rising sharply thanks to a focus on liquids-rich gas wells in unconventional gas plays. In response to the rising bounty of propane, infrastructure development in Canada has focused on export projects, and in 2019, the completion of the new Ridley Island Propane Export Terminal in British Columbia enabled the first overseas exports of propane from Canada’s west coast, allowing Western Canadian producers to access destination markets beyond just the U.S. for the first time. Later this year, Pembina Pipelines, a developer of energy infrastructure projects across Western Canada, will complete a new propane export terminal just outside Prince Rupert, BC, further boosting propane exports to overseas markets. Today, we take a closer look at propane supply issues, Pembina’s new propane export terminal and recently announced plans to further expand the terminal’s export capacity.
It’s almost Spring 2020 and energy markets are making another turn. Prices have been clobbered by a combination of low, weather-related demand and COVID-19. Tight capital markets have the E&P sector hunkered down and the pace of production growth is slowing. But at the same time, new pipelines out of the Permian and Bakken are under construction; some are already ramping up flows. Long-delayed LNG terminals and NGL-consuming petrochemical plants are coming online. Essentially all growth in crude and gas — plus most incremental NGL production — is being exported to global markets, and those markets are pushing back. All this has huge implications for commodity flows, infrastructure utilization and price relationships for oil, natural gas and NGLs. Which means that it’s time for RBN’s School of Energy, with all of our curriculum and models updated for the realities of today’s energy markets. Today — in a blatant advertorial — we’ll examine our upcoming School of Energy and explain why this time around we are concentrating even more than usual on NGLs.
There is no such thing as a typical NGL barrel. For example, the composition of y-grade production out of the Marcellus is significantly different from y-grade out of most of the Permian. And it is not just gas processing engineers who care. The make-up of an NGL barrel is inextricably linked to the value of that barrel. The reason is pretty simple: there’s a big difference in the value of each of the five NGL products. These days, natural gasoline is worth nearly eight times as much per gallon as ethane. Normal butane is worth 1.6X as much as propane. Consequently, the more natural gasoline and normal butane in your barrel versus the amounts of ethane and propane, the more the barrel is worth. So it’s important to anyone trying to follow the value added by gas processing and related infrastructure to understand where these numbers come from and how much the composition of a barrel can vary from basin to basin, or for that matter, from well to well. In Part 2 of our series on gas processing, we turn our attention to the variability in the mix of NGL production and its implication for processing uplift.
Wouldn’t it be nice if everything you needed to keep up with the market was right there on your phone or tablet? And it would be even handier if the data and stories organized themselves just for you, around topics you care about the most. Such a technology would address a formidable challenge we all face: keeping up with the torrent of market information coming at us from trading platforms, online services, trade publications, you name it. It would pull everything you needed into a single database and then organize information on the fly around whatever topic matters most to you at a point in time. And it would be able to reorganize that information on demand as market data ebbs and flows. Over the past few months, we’ve designed an app that tackles this challenge head-on. Today we are introducing the concept of ClusterX, explaining how it works, and giving you the opportunity to help us roll out our new technology to the RBN blogosphere. Warning: this is a blatant advertorial for our new energy market analytics app.
OK, we admit it. Our title may be a bit of an overstatement in early 2020, but it was absolutely true back in 2012, when the frac spread was $13/MMBtu. These days, the frac spread — the differential between the price of natural gas and the weighted average price of a typical barrel of NGLs on a dollars-per-Btu basis — is only $2.48/MMBtu as of yesterday. But with Henry Hub natural gas prices in the doghouse — they closed on February 11 at $1.79/MMBtu — getting $4.27/MMBtu for the NGLs extracted from that gas, or an uplift of 2.4x, is still a pretty darned good deal. And that’s Henry Hub. Natural gas prices are lower in all of the producing basins, and are likely headed back below zero in the Permian this summer. So even with NGL prices averaging 30% lower than last year, the value of NGLs relative to gas can be a big contributor to a producer’s bottom line — assuming, of course, that the producer has the contractual right to keep that uplift. Today, we begin a blog series to examine the value created by extracting NGLs from wellhead gas, including processing costs, transportation, fractionation, ethane rejection, margins, netbacks and the myriad of factors that make NGL markets tick. We will start with the frac spread — what it tells us in its simplest form, how we can improve the calculations so it can tell us more, and, just as important, the economic factors that the frac spread excludes.
For a few years now, the Shale Revolution has been opening up development opportunities hardly anyone would have thought possible in the Pre-Shale Era. For example, new crude oil, natural gas and NGL pipelines from the Permian to the Gulf Coast, lots of new fractionators and steam crackers, as well as export terminals for crude, LNG, LPG, ethane and, most recently, ethylene. And here’s another. Thanks to the combination of NGL production growth and new ethylene supply — plus increasing demand for alkylate, an octane-boosting gasoline blendstock — the developer of a novel ethylene-to-alkylate project along the Houston Ship Channel has reached a Final Investment Decision (FID). Today, we discuss how the FID is driven by both supply-side and demand-side trends in the NGL and fuels markets.
Over the past two years, MPLX has been ramping up its midstream development activity in the Lone Star State, or more specifically in the “Permian-to-Gulf” market, where it’s been building or buying into gathering systems, gas processing plants, and crude and natural gas takeaway pipelines, among other things. Marathon Petroleum Corp.’s midstream-focused master limited partnership also has been in hot pursuit of a number of possible NGL-related projects, including MPLX’s proposed Belvieu Alternative NGL (BANGL) Pipeline and three big fractionation plants in the Sweeny, TX, area, and a planned LPG export terminal in Texas City, TX. As a group, these projects would require millions of barrels of underground salt-cavern storage capacity for y-grade and NGL purity products along the Texas coast, as well as multiple pipeline connections to move the stuff to where it needs to be. Today, we continue our series on Gulf Coast NGL storage with a look at the NGL side of the MLP’s Permian-to-Gulf strategy.
Much as production growth in the Permian required the development of new pipeline capacity to take away crude oil, natural gas and NGLs, increasing activity in the Williston Basin has spurred the need for incremental capacity to move all three of the energy commodities out of western North Dakota and eastern Montana. For NGLs, the recent start-up of ONEOK’s Elk Creek Pipeline has been the answer to producers’ prayers — not just in the Williston Basin (home of the Bakken formation), but also in the Rockies’ Powder River and the Denver-Julesburg (D-J) basins, through which the new, 240-Mb/d pipeline passes on its way to Bushton, KS. Elk Creek’s timing couldn’t have been better: it came online just as a number of new gas processing plants entered commercial service in the Williston Basin, and just in advance of possible Btu restrictions on the all-important Northern Border gas pipeline that may force cutbacks in ethane rejection. Today, we explain why the Elk Creek NGL Pipeline helps resolve a number of challenges Bakken producers have been facing.
Propane stockpiled in Canada has often been a mid-winter godsend for propane consumers in the U.S. Midwest and Great Plains states. If supplies in PADD 2 ever got tight due to unusually cold weather, greater-than-normal crop-drying demand and/or kinks in the U.S. supply chain, the higher prices spurred by the shortfall would incent more Canadian propane to be piped, railed or trucked south. This winter may be different, though. A new propane export terminal in British Columbia and steady-as-she-goes exports from the U.S.’s northern neighbor to PADDs 2 and 5 have left Canadian propane inventories nearly one-third lower than a year ago, and propane in the Edmonton, AB, hub is selling at a far-from-typical premium to propane at Conway, KS, and Mont Belvieu, TX. Today, we explain why a supply-demand imbalance in the U.S. heartland this winter might be harder to fix.
Cold weather and spiking demand from Midwest and Great Plains farmers trying to dry their late-maturing, soggy crops have sent the PADD 2 propane market into a tizzy. Supply is not a major issue — propane inventory levels in the region are only a little below average, and stocks are plentiful along the Gulf Coast in PADD 3 — but distributing propane by rail and truck for crop-drying use has been a bigger-than-normal problem. As a result, farmers are scrambling to get more of the fuel, and propane prices in the U.S. heartland have been skyrocketing. Worse yet, Canada may not be able to come to the rescue as it has in the past, because its propane exports to Asia are up and its inventories are down. Today, we review recent developments on the fuel front in the nation’s breadbasket.