With frac sand use — and costs — on the rise in the Permian, a number of exploration and production companies (E&Ps) are becoming more involved in managing sand acquisition and logistics. It’s not an easy job, because even though a greater share of the frac sand used in Permian wells is expected to come from local, West Texas sand mines in the coming year, those “last mile” logistics — the delivery of sand by truck from the mine, plus unloading and storage of sand at the well site — are especially complex. Today, conclude our series on frac sand with a look at the challenges E&Ps face when they assume supply chain responsibility for sand.
Back in 2015, U.S. production of superlight crude oil and condensate had been on the rise for five years, driven primarily by boom times in the Eagle Ford shale play in South Texas. Condensate was selling for several bucks-a-barrel less than light-crude benchmark West Texas Intermediate (WTI), the U.S. government had recently approved the export of minimally processed condensate, and new condensate splitters were being built to allow refineries to use more high-API-gravity liquids. Fast forward to now, though, and production of superlight crude and conde is off by one-third — the lighter the material, the steeper the decline — a barrel of conde is selling for several dollars more than WTI and a lot of those new splitters are running at far less than full capacity. As for exports of neat conde, they’ve dropped to almost zero, and whatever superlight crude and conde that is being exported goes out as part of blended crude. But things could be about to change again, possibly in a big way. Today, we begin a new blog series on the chaotic U.S. conde and superlight crude market.
U.S. exports of crude oil really took off in 2017, and the exporting pace has only accelerated this fall. In the 10 weeks since mid-September, crude exports have averaged nearly 1.6 million barrels/day, with the vast majority of that oil leaving by ship out of ports along the Gulf Coast. The lifting of the ban on most crude exports two years ago this month and the growth in exports since then have put a spotlight not only on coastal storage facilities, pipelines and marine docks, but also on the huge vessels used to transport crude to far-away destinations. Today, we discuss crude-export vessel configurations, tanker chartering practices, ship-loading challenges and transportation costs.
The crude oil-carrying Dakota Access Pipeline (DAPL) has been up and running for almost six months now, creating new market dynamics in the Bakken. But these changes haven’t garnered all that much attention — they’ve been overshadowed by talk of Permian production growth, Gulf Coast pricing and Cushing pipeline capacity. Now though, with news of super-long three-mile laterals and increasingly positive producer sentiment, the Bakken is once again shifting into the limelight — and the 525-Mb/d DAPL from western North Dakota to Patoka, IL is center-stage. Today, we discuss DAPL’s effects on Bakken crude prices, market access, other takeaway pipelines and crude by rail.
Exploration and production companies (E&Ps) in the Permian have made great strides in reducing key elements of their drilling and completion expenses. However, many E&Ps have struggled in their efforts to trim one key element: their frac sand costs, which can account for 20% or even 25% of the total bill per high-intensity well. Now, with new sand mines coming online in West Texas and with traditional Upper Midwest sand suppliers eager to protect their market share, many producers are looking for multiple ways to lower the total delivered cost of their sand while making the challenging tasks of sand delivery and handling much more efficient. Today, we continue our blog series on recent developments in the frac sand arena.
A number of producers in the Permian and other shale plays are rethinking their strategies for using, procuring and delivering frac sand — all with the aim of minimizing sand costs, which account for a sizable and increasing share of total drilling and completion expenses. The focus on frac sand stems from evolving completion strategies that are pumping ever-larger volumes of sand into horizontal wells resulting in sharply higher hydrocarbon production. That has caused sand demand — and prices — to soar, and prompted the rapid development of new sand mines close to shale-production hot spots like West Texas, in part to reduce sand transportation costs. Today, we continue our blog series on recent developments on the frac sand front.
Two months ago, U.S. crude oil exports skyrocketed, and they have averaged 1.6 MMb/d since mid-September, driven by a Brent-WTI differential above $6/bbl — higher than it has been in over two years. At one point, the steep differential and surging exports were blamed on Hurricane Harvey, then on renewed OPEC discipline and a political risk premium associated with a shakeup in the Saudi hierarchy. But the reality is that these factors are only small pieces of the equation, with pipeline transportation bottlenecks from Cushing and the Permian down to the Gulf Coast being much more important factors in the widening Brent-WTI price spread. Today, we begin a blog series examining how these pipeline capacity constraints triggered the expanded price differential, and how the differential then enabled high crude oil export volumes.
Wide swings in the value of Permian crude oil in Midland, TX, the storage and distribution hub in Cushing, OK, and Gulf Coast points like Houston in recent months have only reinforced the importance of destination flexibility. The ability of Permian producers and shippers to access multiple takeaway pipelines and, with that, the market that will give them the highest possible price for their product, is being enhanced by the addition of new intra-basin shuttle pipelines, gathering systems and hybrid gather-and-shuttle networks. These new pipes are designed to help connect new wellheads across the Permian’s Midland and Delaware basins with two, three or even more takeaway pipelines, adding new robustness to the region’s infrastructure and enabling crude to flow to where it is most valued at any given time. Today, we discuss highlights from our new Drill Down Report on Permian crude oil shuttle pipelines and gathering systems.
Since the ban on exports of U.S. crude oil was lifted in December 2015, export volumes have soared, and for the week ending October 27, 2017, they surpassed 2 million barrels/day (MMb/d) for the first time ever, according to Energy Information Administration (EIA) statistics. And while exports slowed last week, it is clear that there’s more to come. But the pace of export growth depends on many things, including the ability of Gulf Coast infrastructure to receive and store increasing volumes of West Texas Intermediate (WTI), SCOOP/STACK, Bakken and other crudes and load it onto ships — the bigger the ship the better. Fortunately, coastal Texas and Louisiana already had extensive crude-related infrastructure in place when the export ban ended just under two years ago, and elements of that have been repurposed to handle exports. Will it be enough? Today, we begin a new blog series on existing and planned storage facilities and marine terminals targeted to support rising U.S. crude oil exports.
In the past year, there have been major changes in the frac sand sector. Exploration and production companies in the Permian and other growing areas have significantly ramped up the volume of sand they use in well completions, catching high-quality sand suppliers in the Upper Midwest off-guard and spurring sharply higher frac sand prices due to the tight supply. At the same time, development of regional sand resources has taken off in the Permian — with close to 20 mines announced with upwards of 60 million tons/year of nameplate capacity possible — and, to a lesser extent, in the SCOOP/STACK, Haynesville and the Eagle Ford. That new capacity should begin easing sand-supply shortfalls next year, reducing sand delivered costs and potentially threatening the dominance of traditional Northern White sand. And more changes are ahead in 2018. Today, we begin a new blog series on fundamental shifts in the all-important frac sand market.
Permian crude oil production now tops 2.5 million barrels a day (MMb/d) and is expected to increase to 3.5 MMb/d by 2022 under RBN’s least optimistic price scenario. If prices hold steady or rise, production in the play could easily surpass 4 MMb/d within five years. But the Permian’s output isn’t just dependent on price. It’s also critically important that sufficient gathering capacity is in place to efficiently transport crude from the lease to central points where oil can flow onto shuttle pipelines or takeaway pipes. Today, we continue our blog series on key infrastructure in the nation’s hottest shale region with a look at a number of existing and planned gathering systems.
The three co-owners of the 1.2-MMb/d Capline Pipeline from St. James, LA, to Patoka, IL, have begun assessing whether there is sufficient shipper interest in reversing the flow of one of the U.S.’s largest crude oil pipelines in the early 2020s. There are good reasons both for ending Capline’s long run as a northbound-flowing pipe and for repurposing the pipeline to help transport heavy western Canadian oil and other crudes south to refineries in eastern Louisiana and Mississippi and to export markets. But there also are logical questions to ask, such as why Capline’s owners envision sending only 300 Mb/d south on the pipe, and why they don’t see the reversal occurring for five years. Today, we examine the forces behind Capline’s possible reversal and the benefits that flipping the pipe’s direction might provide.
U.S. crude exports continue to takeoff — increasing during the week ended September 29, to a new record just under 2 MMb/d, according to the Energy Information Administration (EIA), with 1.3 MMb/d in the first week of October followed by 1.8 MMb/d in EIA’s Wednesday report. The crude exodus is primarily occurring from port terminals along the Gulf Coast and is expected to continue as expanding Permian basin shale production is shipped directly to marine docks by pipeline. Recent and planned expansions to crude storage are largely linked to demand for new capacity at marine docks staging cargoes for export. In today’s blog, Morningstar’s Sandy Fielden details the rapid growth of commercial crude storage capacity at Gulf Coast terminals since 2011.
Permian producers and shippers want to be able to transport their crude oil to whichever destination will give them the best netbacks. But that’s a moving target, so what they really need is destination optionality — something they can only get if the gathering systems and shuttle pipelines that move oil from the lease tie into multiple takeaway pipelines with different end-points like Houston, Corpus Christi and Cushing. Midstream companies are clamoring to meet that need by expanding existing shuttle pipelines and building new ones. Today, we continue our review of intra-Permian shuttle pipelines.
Expectations of continued production growth in the Permian’s Delaware Basin — and the need to provide crude oil producers and shippers with multiple connections to takeaway pipelines out of the play — are spurring the expansion of existing shuttle pipelines and the development of new ones. A number of these shuttle pipes are part of larger gathering-and-shuttle systems whose pipe diameters increase as they move crude downstream toward takeaway interconnections. Today, we continue our review of intra-basin pipelines that transport oil to takeaway pipes and provide destination optionality in the process.