Energy Transfer’s Mariner East pipeline system was supposed to help resolve a growing problem for producers in the “wet” Marcellus and Utica plays — namely, the need to transport increasing volumes of LPG out of the Northeast, especially during the warmer months, when in-region demand for LPG is low. The pipeline system also was meant to spur LPG and ethane exports out of Energy Transfer’s Marcus Hook marine terminal near Philadelphia. So how are things going? Well, the now five-year-old, 70-Mb/d Mariner East 1 pipeline, designed to transport ethane and propane, has been offline ever since a sinkhole exposed a part of the pipe late last month. The 275-Mb/d Mariner East 2 pipe is finally in operation and enabling a lot more LPG to move to Marcus Hook, but for now it can only run at about 60% of its capacity. And last Friday, a key Pennsylvania regulator suspended its review of outstanding water permit applications for the remaining piece of ME-2 and the parallel 250-Mb/d ME-2 Expansion project, and threw into doubt how long it might take to finish the Mariner East system and ramp it up to full capacity. Today, we begin a series on recent Mariner East developments and explain how, despite the mixed bag of Mariner East news in recent weeks, the situation is not as bad as it may seem.
Well, it finally happened. After several years of assessing the possible development of a large, integrated propane dehydrogenation (PDH) plant and polypropylene (PP) upgrader unit, a joint venture of Canada’s Pembina Pipeline and Kuwait’s Petrochemical Industries Co. (PIC) earlier this week announced a final investment decision (FID) for the multibillion-dollar project in Alberta’s Industrial Heartland. The new PDH/PP complex won’t come online until 2023, but when it does, it will provide yet another new outlet for Western Canadian propane, which has been selling at a significant discount in recent years. Today, we discuss Pembina and PIC’s long-awaited PDH/PP project, Inter Pipeline’s development of a similar project nearby, Western Canadian propane export plans — and what they all mean for propane prices.
The U.S. started exporting ethane by ship less than three years ago, first out of Energy Transfer’s Marcus Hook terminal near Philadelphia and then from Enterprise Products Partners’ Morgan’s Point facility along the Houston Ship Channel. Good news for NGL producers, right? Well yes, sort of. Because while waterborne export volumes rose through 2016, 2017 and the first seven months of last year, they’ve been flat-to-declining ever since, with further ethane-export growth hampered primarily by a lack of international demand. That demand may soon be ratcheting up — mostly in China, but also in Europe — but it won’t happen overnight. Today, we discuss ethane export trends, the Morgan’s Point and Marcus Hook marine facilities, and plans for new ethane export capacity tied directly to new overseas ethane crackers.
LPG export terminals along the Gulf Coast account for more than nine of every 10 barrels of propane and normal butane that are shipped from the U.S. to foreign buyers. That makes perfect sense, given the terminals’ proximity to major NGL production areas like the Permian, the Eagle Ford and SCOOP/STACK, and to the world-class fractionation hub in Mont Belvieu, TX. But, increasingly, LPG terminals on the East and West coasts, are growing in significance. On the Atlantic side, Marcus Hook, near Philadelphia, is enabling more and more volumes of Marcellus/Utica-sourced propane and butane to reach overseas markets. And, as we discuss in today’s blog, West Coast exports are on the rise as well, with Petrogas’s Ferndale terminal in Washington state providing a straight shot across the Pacific to Asia for propane and butane fractionated in Western Canada, plus a good bit more LPG export capacity under development in British Columbia.
U.S. production of natural gas liquids is projected to increase by 17% this year, and by another 10% in 2020, according to RBN’s forecast. These gains will result in similar increases in the output of propane and normal butane — two NGL purity products generally referred to as LPG — and, with U.S. demand for LPG expected to stay relatively flat, most of the incremental volumes will be sent to export terminals for shipment to foreign buyers. The question is, will the nine U.S. marine terminals that are equipped to send out LPG have enough capacity to handle the much-higher flows? Today, we continue our series with a review of four smaller export terminals along the Gulf and East coasts.
Way back in 2012, the U.S. flipped from being a net LPG importer to a net exporter. Since then, exports by ship have skyrocketed, up from 0.3 MMb/d in 2013 to more than 1.1 MMb/d at year-end 2018, an astronomical compound annual growth rate (CAGR) of 30%. The vast majority of waterborne exports was out of a handful of LPG terminals along the Gulf Coast. These facilities — plus Ferndale in the Pacific Northwest and Marcus Hook near Philadelphia — so far have managed to handle the increasing flow of LPG, but with U.S. NGL production still rising, it looks like new export capacity is needed — and is on the way. All the while, imports of LPG, almost all from Canada, have remained relatively flat, averaging only 130 Mb/d in the 2013-18 period. Today, we begin a series on existing and planned LPG export capacity along the Gulf, West and East coasts — and what’s driving the build-out of these assets.
Production of natural gas liquids in the Rockies has increased by half since the end of 2012, with the bulk of the output — and those gains — coming from the greater Niobrara play in Colorado and Wyoming. As a result, a number of NGL pipelines out of the Rockies are now running full or close to it, and midstream companies are planning a mix of new pipelines, pipeline expansions and pipeline conversions with the aim of easing takeaway constraints by the latter half of 2019. But, with crude oil prices tanking and crude-focused producers reevaluating their drilling and completion plans, could the Niobrara be headed for an NGL takeaway over-build? In today’s blog, we continue our series with a look at existing and planned NGL pipes out of the Denver-Julesburg (D-J) and Powder River basins.
Crude oil takeaway constraints out of the Permian are a fresh reminder that, in the Shale Era, production gains can far outpace the ability of the midstream sector to build new pipelines. Similarly, an increasing share of the rising volumes of crude flowing through the Cushing, OK, hub wants to move to the Gulf Coast, but the existing Cushing-to-coast pipeline systems are full and midstreamers are scrambling to add more capacity. Pipeline constraints aren’t limited to crude, of course. In the Niobrara’s Denver-Julesburg Basin, rapid gains in NGL production threaten to overwhelm the pipelines carrying mixed NGLs to fractionation hubs. What can be done? In at least some cases — including all of those mentioned above — there are opportunities to convert NGL pipelines to crude service, or vice versa. Today, we look at efforts under way to repurpose existing pipes to add needed takeaway capacity pronto.
Two months ago, NGL prices and market differentials were soaring, in large part due to fractionation capacity constraints on the Gulf Coast at Mont Belvieu. The constraints have not eased, yet the same prices and differentials have come crashing down from those lofty levels. Why has this happened, you ask, and how long will it last? There are a lot of factors contributing, but two of the most significant are seasonal NGL demand shifts and what’s going on with crude oil. Today, we examine the recent swings in NGL prices and market differentials and what may be around the next corner for these markets.
To fire on all cylinders — especially during a period of strong high crude oil prices and rising production — the U.S. energy sector depends on midstream infrastructure networks that can efficiently handle the transportation and processing of every type of hydrocarbon that emerges from the wellhead. It’s no secret that rapid production growth in the Permian has left the red-hot West Texas play short of crude-oil pipeline capacity, and midstream companies there have also struggled to keep pace with natural gas takeaway needs too. What’s less well known is that fractionation capacity at the all-important NGL hub in Mont Belvieu, TX, is nearly maxed out, and that some Permian producers — and others — are now scrambling to find other places to send their incremental NGL barrels for fractionation into purity products. We put this issue front-and-center earlier this week in Hotel Fractionation. Today, we discuss highlights from the first of two planned Drill Down Reports on fractionators and other key assets at the nation’s largest NGL hub, and the potentially broader effects of a fractionation-capacity shortfall.
Y-grade, welcome to the Hotel Fractionation. You can check in any time you like, but you can never leave! OK, so that’s a bit of an overstatement. But there is no doubt that the U.S. NGL market has entered a period of disruption unlike anything seen in recent memory. Mont Belvieu fractionation capacity is, for all intents and purposes, maxed out. Production of purity NGL products is constrained to what can be fractionated, and with ethane demand ramping up alongside new petchem plants coming online, ethane prices are soaring. But that’s only a symptom of the problem. Production of y-grade — that mix of NGLs produced from gas processing plants — continues to increase in the Permian and around the country. Sooo … If you can’t fractionate any more y-grade, what happens to those incremental y-grade barrels being produced? How much can the industry sock away in underground storage caverns? Does it make economic sense to put large volumes of y-grade into storage if it will be years before it can be withdrawn? — i.e., “you can never leave.” And what happens if y-grade storage capacity fills up? Today, we begin a blog series to consider these issues and how they might impact not only NGL markets, but the markets for natural gas and crude oil as well.
The Utica and “wet” Marcellus plays in eastern Ohio, northern West Virginia and western Pennsylvania are producing increasing volumes of natural gas liquids and field condensates that need to be moved to market. In response, MPLX, a master limited partnership formed by Marathon Petroleum Corporation (MPC) six years ago, has been implementing a multi-part strategy to develop new or expanded pipeline takeaway capacity through the Midwest to deal specifically with the heaviest NGLs — natural gasoline and other pentanes — and with field condensates. That work is now largely done, the results have been positive, and MPLX is now undertaking the next phase of its strategy that will further expand the system’s capacity and add a new element: the ability to transport batches of two other, lighter NGLs — normal butane and isobutane — on a few of the same pipelines. Today, we discuss the next steps the company is taking to facilitate the transport of liquid hydrocarbons out of the Utica and Marcellus.
Fast-rising NGL production in the Permian, SCOOP/STACK and other plays is testing the ability of fractionators to keep up, and spurring the development of new NGL pipelines — and new fractionation plants, not just in the Mont Belvieu hub but elsewhere along Texas’s Gulf Coast. By our count, more than 1 MMb/d of new fractionation capacity is under development in the Lone Star State, and while some projects are more solid and certain than others, it’s fair to say we’re in for at least a mini-boom in fractionator construction after a multiyear lull. Today, we review the Texas fractionation projects being planned and begin assessing whether they will come online as quickly as they will be needed.
The NGL storage and fractionation hub at Mont Belvieu, TX, grabs all the attention, but more than 1 MMb/d of fractionation capacity — nearly one-third of Texas’s total — is located elsewhere in the Lone Star State. And with NGL production and demand for fractionation services soaring in the Permian, SCOOP/STACK and other nearby plays, the market will need all the fractionation capacity it can find. We’ve heard that there’s little, if any, gap between what the existing fractionators in Mont Belvieu can handle and what they’re being asked to process. That’s music to the ears of fractionation-plant owners elsewhere in Texas — assuming they aren’t already at capacity themselves, they might be able to pick up some overflow business from Mont Belvieu. Today, we continue our review of fractionators and other key NGL-related infrastructure along the Gulf Coast.
Mont Belvieu may be the epicenter of NGL storage, fractionation and distribution along the Gulf Coast, but the rest of Texas offers almost half as much fractionation capacity — about 1 MMb/d of it — and a good bit of storage and pipeline connectivity too. These are particularly important facts in the summer of 2018, when demand for fractionation services in Mont Belvieu is at or near an all-time high and increasing volumes of NGLs are headed toward the hub. So what else has the Lone Star State got on the fractionation and NGL storage front? And are these assets experiencing the same strong demand as their counterparts in Mont Belvieu? Today, we continue our review of fractionators and key NGL-related infrastructure.