U.S. crude oil, NGL and gas markets have entered a new era. Exports now dominate the supply/demand equilibrium. These markets simply would not clear at today’s production levels, much less at the flow rates coming over the next few years, if not for access to global markets. This year, the U.S. may export 20-25% of domestic crude production, 15% of natural gas and 40% of NGLs from gas processing, and those percentages will continue to ramp up. What will this massive shift in energy flows mean for U.S. markets, and for that matter, for the rest of the world? The best way to answer that question is to get the major players together under one roof and figure it out. That’s the plan for Energy xPortCon 2019. Warning!: Today’s blog is a blatant advertorial for our upcoming conference.
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.
During 2018, U.S. crude oil, natural gas and NGL production hit new all-time highs almost every month. Oil production grew by a staggering 1.7 MMb/d from January to December, an increase of about 18%. NGLs soared even more: by 27%, up 1.0 MMb/d over the same 12-month period. Natural gas production zoomed skyward by 10 Bcf/d, a gain of about 13%. All this new supply came on in a price environment marked by wild swings. WTI ran up from $60/bbl to $75, then collapsed below $50. Henry Hub gas spiked to nearly $5/MMBtu, then beat a hasty retreat back to the $3/MMBtu range. Permian gas traded negative. Ethane prices blasted to the moon (62 c/gal), then crashed back to earth (below 30 c/gal). Is this the way it’s going to be? Massive production growth, extreme price volatility, widespread market uncertainty? It’s impossible to answer such a question, right? Nah. All we need to do is stick our collective RBN necks out one more time, peer into our crystal ball, and see what 2019 has in store for us.
One way or the other, all of 2018’s Top 10 blogs had something to do with infrastructure. There’s not enough. Or it’s taking too long to come online. Or there is too much being built too soon. Even the financial underpinning of U.S. energy infrastructure development — the MLP model — ran into tough sledding in 2018. Then, toward the end of the year, all of the best-laid infrastructure planning got whacked by the crude-market wild card: prices crashing below $50/bbl. We scrupulously monitor the website “hit rate” of the RBN blogs that go out to about 26,000 people each day and, at the end of each year, we look back to see what generated the most interest from you, our readers. That hit rate reveals a lot about major market trends. So, once again, we look into the rearview mirror to check out the top blogs of the year based on the number of rbnenergy.com website hits.
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.
For 65 years, Enbridge’s Line 5 has been a critically important conduit for moving Western Canadian and Bakken crude oil and NGLs east across Michigan’s upper and lower peninsulas and into Ontario, where the now-540-Mb/d pipeline feeds Sarnia refineries and petrochemical plants. Some crude from Line 5 also can flow east from Sarnia to Montreal refineries on Line 9. But Enbridge has been under increasing pressure to shut down Line 5 over concern that a rupture under the Straits of Mackinac might cause major environmental damage. At long last, the state of Michigan and Enbridge have reached an agreement to replace the section of Line 5 under the straits by the mid-2020s, and to take steps in the interim to enhance the existing pipeline’s safety. In today’s blog, we consider the significance of the Enbridge pipeline and of the newly reached accord.
Crude oil production in the Rockies’ Niobrara region is up by more than 50% since the beginning of last year, spurred on by higher oil prices, ample oil pipeline takeaway capacity, and other positive factors. Natural gas and NGL production in the Niobrara — which includes both the Denver-Julesburg (D-J) Basin and the Powder River Basin (PRB) — has been rising too, to the point that there’s a scramble on to develop new gathering systems, gas processing plants as well as gas and NGL pipeline capacity. A number of exploration and production companies are upbeat about the region’s prospects; so are some midstreamers. But there’s a dark cloud on the horizon — at least in Colorado, where voters will decide in a few weeks whether to significantly restrict where new wells can be drilled. Is the Niobrara poised for continued growth or not? Today, we kick off a new series on Rockies production, infrastructure and prospects.
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.
It seems like everyone wants production out of the Permian these days — at least everyone who works for a pipeline company. The addition of five major greenfield crude oil pipes plus a host of expansion projects could bring Permian takeaway capacity up to 8.0 MMb/d from only 3.3 MMb/d today, with almost all of the incremental barrels destined for export markets. It’s a similar story for natural gas, with seven new pipes in the works to bring 2.0 Bcf/d each to Corpus Christi, Houston, or Louisiana, again with most of the molecules targeting exports. Not to be left behind, at least 27 new Permian gas processing plants are in development, and five new pipeline projects could bring 1.6 MMb/d of y-grade NGLs to the Gulf Coast. It’s a darned good thing that everyone in the global energy markets wants all that Permian production, right? What will this mean for the Permian and, for that matter, for the rest of the U.S. and the world? The only way to answer that question is to get the major players together under one roof and figure it out. That’s the plan for PermiCon 2018. Warning! Today’s blog is a not-so-subliminal advertorial for our upcoming conference.
There has never been anything like the 2018 Permian Basin. In just five years, oil production has tripled, gas production has doubled and NGL output is up about 2.5 times. Crude oil pipelines out of the Permian are filled to the brim and the differentials between crude in Midland and both the Gulf Coast and Cushing have blown out. It is the same for natural gas, with pipe capacity nearly maxed out and basis wide. So far, most Permian NGLs have avoided a similar traffic jam in the local market, only to run into constraints downstream. But the overall Permian market is headed for a breakout! Massive infrastructure development is coming to the basin and the takeaway capacity constraints will be history — at least for a while. What will this mean for the Permian market, and for that matter, for markets across North America and the globe? Clearly, we need to get the major players together under one roof and figure it out. And that’s just the plan for PermiCon 2018. Our goal for this unique conference is to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence. Warning! Today’s blog is an unabashed advertorial for our upcoming conference.
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.