On October 25, a major consolidation of two Canadian oil and gas companies was announced with the planned merger of Cenovus Energy and Husky Energy. The prospective consolidation will offer the opportunity for corporate-level synergies and, over the longer term, for the physical integration of some of the companies’ operations, especially in Alberta’s oil sands. In today’s blog, we discuss some of the more nuanced elements of the consolidation, including potential improvement in crude oil market access and the larger presence of the combined company in PADD 2 refining, a sector that has taken a major hit during the pandemic. This blog also introduces a new weekly report from RBN and Baker & O’Brien: U.S. Refinery Billboard.
Daily energy Posts
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.
Anything but normal might be the best way to characterize today’s market for normal butane. Butane production at gas processing plants and fractionators is at or near an all-time high. Butane consumption by steam crackers is maxed out, and so were butane exports until new dock capacity came online this fall. Butane inventories? They’ve risen to record levels too, and this summer, butane prices fell to their lowest mark in more than a decade. Now, with winter-gasoline blending season in high gear and new room for export growth, butane prices at Mont Belvieu are up more than 35% from where they stood a month and a half ago. What does all this mean for the butane market this winter? Today, we discuss recent trends in normal butane production, consumption, exports and stocks.
U.S. production and exports of propane have soared through the 2010s, and an increasing share of the propane loaded onto gas carriers at U.S. Gulf Coast terminals is headed to the Far East. The numbers are staggering. So far in 2019, 57% of propane produced from U.S. gas processing plants and refineries has been sent overseas, with about half of that total moving to Asian markets. With exports to Asia now such an integral piece of the propane supply/demand balance, the price of U.S. propane during most of the year is influenced more by the markets in Japan, South Korea and China than it is by demand in Iowa, Michigan and Pennsylvania. The challenge for U.S. propane marketers, producers and exporters is that, to the uninitiated, the Asia propane market is quite convoluted, being dominated by obscure market mechanisms known as FEI and Ginga. Today, we continue our series on international LPG trading with an explanation of how these mechanisms work together to establish propane prices in Asia and, by extension, the Gulf Coast.
In October, some 45 MMbbl of liquefied petroleum gases (LPGs) were loaded onto ships and sent out from U.S. ports, more than 80% of it from Texas Gulf Coast terminals. Most propane and normal butane exports are tied to long-term deals between U.S. suppliers and overseas buyers, but a substantial share involves third-party LPG traders who cut deals to buy LPG, arrange for shipping and terminaling, then sell the LPG to buyers in distant lands. How exactly does all this happen? Today, we continue a series on how U.S.-sourced LPG makes its way to Asia, Europe and other key export markets.
U.S. propane production has been on the rise for most of 2019, but propane consumption by steam crackers has been reined in by poor economics, and propane exports have been constrained by export-capacity shortfalls. That’s led to a big buildup in propane inventories, which stand at near-record levels as the market prepares for a winter heating season that is forecasted to be milder than normal. So we’re in for only a modest draw on propane stocks between now and spring, right? Not necessarily. There’s change in the air regarding propane supply, cracker demand and export capacity and, as we learned in the balmy winter of 2016-17, the U.S. propane market isn’t nearly as dependent on the weather as it used to be. Today, we assess recent market developments and explain why a big decline in propane stocks is a real possibility.
U.S. LPG export volumes have climbed to astronomical levels this year. Almost 60% of U.S. propane production, or about 1.3 MMb/d on average so far in 2019, along with a sizable volume of butane, is being shipped to overseas markets, mostly to Asia. As anyone who’s talked shop with an LPG trader knows, international trading of propane and butane (collectively LPGs — Liquified Petroleum Gas) is a wild, roller-coaster kind of business. But how exactly does it all work? How do the players involved acquire the volumes, cut the deals with export dock owners, arrange for shipping and sell the cargoes to buyers? And, most importantly, how do these shippers make money? Today, we begin a series on international LPG trading that looks behind the curtain and drills down into the nuances that make the difference between success and failure in this traditionally opaque world.
The ready availability of low-cost propane, the expectation of renewed growth in global propylene demand and other factors are spurring development of another round of propane dehydrogenation plants in North America. Three PDH plants — two in Alberta and one in Texas — already are under construction and scheduled to come online in the 2021-23 period. Now, Enterprise Products Partners has committed to building a second PDH plant at its NGL/petchem complex in Mont Belvieu, TX, and PetroLogistics — which completed the U.S.’s first PDH plant in 2010 — has selected the technology it will use for a new facility it now plans to build along the Gulf Coast. Today, we discuss planned PDH capacity additions in the U.S. and Canada and what’s driving their development.
New fractionation plants, steam crackers and export facilities are being built along the Gulf Coast, all spurred by rising U.S. production of natural gas liquids. This incremental NGL output and these new projects are putting serious pressure on existing NGL pipeline and storage infrastructure, and prodding the development of new salt-cavern storage capacity for mixed NGLs, NGL purity products, and ethylene and other olefins. Also, new, expanded and repurposed pipelines to enhance NGL-related flows throughout the region are in the works. Today, we continue our series on NGL storage facilities along the Gulf Coast with a look at Easton Energy Services’ plans for more underground storage capacity in Markham, TX, and new NGL and olefin pipelines.
Demand for ethane from U.S. steam crackers is rising as recently completed ethane-only crackers ramp up to full production and additional crackers are finished. To keep pace with demand growth, a portion of the ethane now being “rejected” into the natural gas stream and sold for its Btu value will instead need to be left in the mixed-NGLs stream and fractionated into purity-product ethane. This raises two questions. First, in which shale plays will this shift from ethane rejection to ethane production occur? And second, how much will ethane prices need to increase to encourage the shift and make the required incremental volumes of ethane available? Today, we continue a series on ethane-market developments with a look at where the next tranche of ethane supply will come from and how high ethane prices might need to rise.