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.
Permian natural gas markets felt a cold shiver this week, but not a meteorologically induced one of the types running through other regional markets. Gas marketers braced as prices for Permian natural gas skidded toward a new threshold: zero! That’s not basis, but absolute price, a long-anticipated possibility that became reality on Monday. The cause is very likely driven, in our view, by continued associated gas production growth poured into a region that won’t see new greenfield pipeline capacity for at least 10 months. What happens next isn’t clear, but expect Permian gas market participants to be a little excitable or jittery over the next few months. Today, we review this latest complication for Permian natural gas markets.
The planned implementation date for IMO 2020 is still more than a year away, but this much already seems clear: even assuming some degree of non-compliance, a combination of fuel-oil blending, crude-slate shifts, refinery upgrades and ship-mounted “scrubbers” won’t be enough to achieve full, Day 1 compliance with the international mandate to slash the shipping sector’s sulfur emissions. Increased global refinery runs would help, but there are limits to what that could do. So, what’s ahead for global crude oil and bunker-fuel markets — and for refiners in the U.S. and elsewhere — in the coming months? Today, we discuss Baker & O’Brien’s analysis of how sharply rising demand for low-sulfur marine fuel might affect crude flows, crude slates and a whole lot more.
Permian oil and gas production may have slammed up against capacity constraints, but that does not mean production growth has ground to a halt. Far from it. In the past 10 weeks, Permian gas production is up another 8% — a gain of almost 700 MMcf/d. Crude production now tops 3.5 MMb/d, with incremental barrels finding their way to market via truck, rail and new pipeline capacity — soon including Plains All American’s new Sunrise project, which will move more Permian crude toward the hub in Cushing, OK. Record-setting volumes of NGLs are streaming their way out of the Permian to Mont Belvieu. This market is moving so fast that if you blink, you’ll miss something important. So to get caught up with all things Permian, last week RBN hosted PermiCon, an industry conference designed to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence. We think PermiCon accomplished that goal, and in today’s blog, we summarize a few of the key points discussed during the conference proceedings.
The crude oil hub at Cushing, OK, has more than 90 MMbbl of tankage, 3.7 MMb/d of incoming pipeline capacity and 3.1 MMb/d of outbound pipes. That’s an impressive amount of infrastructure by any standard. The real marvel of the place, though, is the variety of important roles it plays and services it provides for a wide range of market participants — producers, midstream companies, refiners and marketers, as well as producer/marketer and refiner/marketer hybrids. To truly understand Cushing — what it does and how it works — you need to know the hub’s assets and how they fit together. Today, we continue a series on the “Pipeline Crossroads of the World” with a look at the companies that own Cushing storage capacity and how that storage is put to use.
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.
Crude oil inventories at Cushing have been in a free fall. After last peaking at more than 69 MMbbl in April 2017, stockpiles have decreased to less than 22 MMbbl recently, nearing all-time lows for tank utilization at the Oklahoma crude-trading hub. While we’ve seen volumes drop quickly in the past, inventories have now declined for 12 straight weeks at a staggering pace. Traders, refiners, and other market participants are starting to fret. Is this just another cyclical trend or are market factors exacerbating the impact? Today, we examine the influence of historical pricing trends on Cushing inventories and why it seems that demand factors are speeding up the drop.
On Thursday, August 9, a U.S. District Court judge approved a request by a Canadian mining company to seize shares of a subsidiary of Petróleos de Venezuela SA (PDVSA) that controls CITGO Petroleum Corp. The ruling was made to satisfy a $1.2 billion arbitration award against the Venezuelan government. While details of the full ruling are yet to be released, this decision could have an enormous knock-on effect on the various other parties seeking payment from the struggling oil company for asset seizures and unpaid debts. Today, we review the assets of CITGO Petroleum Corp., the U.S. arm of PDVSA.
Federal regulators are preparing to accelerate their review of a wave of applications to build new liquefaction plants and LNG export terminals — most of them sited along the Gulf Coast and scheduled for commercial start-up in the early 2020s. Only a few of the multibillion-dollar projects are likely to advance to final investment decisions (FID), construction and operation, but even they will have profound impacts on U.S. natural gas production, pipeline flows, and the global LNG market. Today, we begin a look at projects still awaiting FIDs, their developers’ efforts to line up Sales and Purchase Agreements (SPAs), and the Federal Energy Regulatory Commission’s (FERC) push to review project applications in a timely manner. Warning: this blog includes a few ever-so-subtle promotions for RBN’s new LNG Voyager Report.
After idling near the 4.6-Bcf/d level for months, piped gas flows to Mexico raced to a record of more than 5 Bcf/d for the first time earlier in July, and have hung on to that level since. This new export volume signifies incremental demand for the U.S. gas market at a time when the domestic storage inventory is already approaching the five-year low. At the same time, it would also signify some much-needed relief for Permian producers hoping to avert disastrous takeaway constraints — that is, if the export growth is happening where it’s needed the most, from West Texas. However, that’s not exactly the case. What’s behind the sudden increase, where is it happening and what are the prospects for continued growth near-term? Today, we analyze the recent trends in exports to Mexico.
For 10 years prior to 2018, the differential between propane prices at the Conway, KS, hub averaged less than a nickel per gallon below Mont Belvieu. In fact, between 2013 and 2017, the price spread was only 3.5 c/gal — excluding a winter 2014 Polar Vortex aberration — which basically reflects the cost of moving barrels 700 miles north-to-south. Not this year, though. After starting 2018 at 3 c/gal, the propane price spread took off, and has averaged 18 c/gal since April, some days moving above 26 c/gal, far above the per-bbl cost of transporting propane 700 miles south to Mont Belvieu. Is it pipeline capacity constraints? In part. But there is a much more significant factor driving this differential wider, not only in the propane market, but across all five of the NGL purity products. What is this mysterious factor? To find out, read on. But here’s your first clue: the problem is not in Kansas anymore.
Necessity is the mother of invention, and the desperate need to transport increasing volumes of crude oil out of the severely pipeline-constrained Permian is spurring midstream companies and logistic folks in the play to be as creative as humanly possible. With the price spread between the Permian wells and the Gulf Coast exceeding $15/bbl in recent days — and possibly headed for $20/bbl or more soon — there's a huge financial incentive to quickly provide more takeaway capacity, either on existing pipelines or by truck or rail. Are more trucks and drivers available? Is there an idle refined-products pipe that could be put back into service? Could drag-reducing agents be added to an existing crude pipeline to boost its throughput? How quickly could that mothballed crude-by-rail terminal be restarted? Today, we discuss frenzied efforts in the Permian to add incremental crude takeaway capacity of any sort — and pronto.
Could it get any worse? Possibly, but the last time we saw petchem margins this bad was in the depths of the 2008-09 economic meltdown, and back then the atrocious margin levels resulted in drastic plant curtailments and in some cases permanent shutdowns. But this time around the petchem industry is in the process of bringing on even more capacity! Is the current situation a fluke, or a harbinger of things to come? In today’s blog we examine recent trends in steam cracker margins, by far the largest demand sector for natural gas liquids (NGLs) and consider what these developments may mean for NGL markets in general, and ethane in particular.
Price differentials in the Permian Basin are widening at a rapid pace. The discount for Midland crude to West Texas Intermediate (WTI) at Cushing has widened by over $4/bbl since the beginning of March and the discount to Magellan East Houston (MEH) crude was over $7/bbl yesterday. Permian production is increasing at a breakneck pace as new players are entering the scene. Private equity-backed exploration and production companies (E&Ps) are no longer just acquiring and flipping acreage, as they are being forced to prove their assets are profitable and can generate a return on investment. The combination of large drilling plans from the majors and new production from these smaller operators — with no new pipeline takeaway capacity in sight — has sent Permian crude pricing into a tailspin. Today, we begin a new series on the recent slide in Permian prices, how new producer strategies are contributing to it, and what it means for pipeline space, trucking and midstream infrastructure.
Crude oil production in the Permian Basin is coming on strong — faster than midstreamers can build pipeline takeaway capacity out of the basin. You can see the consequences in price differentials. On Friday, the spread between Midland, TX and the Magellan East Houston terminal (MEH) on the Gulf Coast hit almost $5.00/bbl, a clear sign of takeaway capacity constraints out of the Permian. We’ve seen different variations of this scenario play out in recent years, most recently last fall, just before the first oil started flowing through the new Midland-to-Sealy and Permian Express III pipelines, and it’s not good news for Permian producers. Now Permian output is again bouncing up against the capacity of takeaway pipelines and in-region refineries to deal with it. As we’ve seen in the past, that’s a warning sign for possible price-differential blowouts. Today, we discuss the fast-changing market dynamics that put Permian producers at risk for another round of depressed Midland prices.