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.
Daily Energy Blog
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.
Shuttle pipelines in the Permian provide high-volume, straight-shot links between crude oil gathering systems and multiple takeaway pipelines out of the play — giving producers and shippers critically important destination optionality. Assuming the shuttles are well-positioned and tied to increasing production on one end and multiple takeaway pipes on the other, existing intra-basin shuttles are highly valued and being gobbled up by major midstream players. And to keep pace with Permian production growth, existing shuttle systems are being expanded and new ones are being planned. Today, we continue our review of key crude-related infrastructure in the nation’s hottest oil production region.
There’s a fierce battle on to build new intra-basin pipelines in the Permian to transport crude oil from gathering systems in hot new production areas to takeaway pipelines out of the play — and to give producers and shippers destination optionality in the process. Participants better bring their A game, though, because successfully developing “shuttle” pipelines in the Permian requires a keen understanding of what’s happening on the field and how best to move the ball forward. Three key factors are lining up producer commitments, providing that critical takeaway optionality, and minimizing the total cost of moving crude from the lease to the Gulf Coast, Cushing or other destinations. Today, we begin a blog series on existing and planned intra-basin oil pipelines in the Permian — what drives the development of these in-demand pipeline “legs” and what it takes for them to succeed.
Argentina has world-class hydrocarbon resources, including shale reserves that rank near the very top globally. But the country’s conventional oil and natural gas production has been sagging for several years, and by 2011 Argentina had flipped from being a net energy exporter to a net importer. It has also been a frequent recipient of LNG cargoes from Cheniere Energy’s Sabine Pass liquefaction plant/export terminal in Louisiana. Things have been turning around of late, though, and there may no longer be a reason to cry for Argentina. Investment in the country’s Vaca Muerta shale play — whose oil and gas potential has been compared to the Eagle Ford Shale in South Texas — is ramping up, drilling and production results are pouring in and at least some midstream infrastructure is being developed to handle what could someday become a Latin American shale boom. Today we take a mirada fresca (or fresh look) at the situation.
Russia is a major producer — and exporter — of crude oil and natural gas, and a major exporter of refined products to boot. So it’s important to keep an eye on what’s going on in Russia, because as U.S. producers and refiners know all too well, what happens halfway around the world often has ripple effects in places like the Permian, the Houston Ship Channel and the Sabine Pass LNG terminal. Today, we discuss Russian crude production and refinery output, its compliance with the OPEC/NOPEC agreement to rein in crude production, and the country’s efforts to steer more of its crude and refined-products exports to Russian ports. This blog is based on the latest FSU Monthly report from our friends at FGE – Facts Global Energy.
Since last winter, the price gap between light crude oil and heavy crude — otherwise known as the light-heavy differential — has narrowed considerably. In February, the price difference between Louisiana Light Sweet crude (LLS) and heavy Maya crude on the Gulf Coast was almost $10/bbl, providing an advantage to refiners who have invested in cokers and other equipment that allows them to run a heavier crude slate. But since June Maya has on average sold for only about $5/bbl less than LLS. Today we examine the shrinking price gap between light and heavy crude and its effect on coking and cracking margins.
It has been a tragic week for the Gulf Coast, with months if not years of cleanup and rebuilding ahead of the region. But already, Houston, Corpus Christi, Port Arthur/Beaumont, Lake Charles and other affected areas are coming back online through the hard work of resilient Texans and Louisianans as well as aid coming in from across the country. And even though the energy industry is also moving quickly to put Hurricane Harvey in the rearview mirror, the damage and disruption have been extensive. It is still much too early to fully understand what has happened and how long the recovery is going to take. But with information that we can piece together from public statements, data analysis and conversations with knowledgeable market participants, it is possible to start developing an assessment of Harvey’s effects. That’s what we will tackle in today’s blog.
The largest single expense associated with operating wells in a number of U.S. shale plays — including the Permian — is the cost of dealing with the large volume of produced water that emerges from wells along with crude oil, natural gas and NGLs. In many cases, produced-water disposal costs account for more than half of total well-operating costs, and every dime or dollar per barrel that an exploration and production company (E&P) needs to spend on produced water increases its break-even cost and saps its bottom line. To rein in trucking and other produced water-related expenses, more E&Ps and midstream companies are (1) developing produced-water treatment plants that allow the water to be reused in hydraulic fracturing and (2) building centralized systems that efficiently transport untreated produced water from multiple wells to treatment plants or to regional disposal wells. Today we continue our surfing-themed series on the effect of sand and water costs on producer economics with a look at how the old ways of dealing with produced water are being replaced by the new.
The stars may finally be aligning for two related crude oil infrastructure projects that, if undertaken, would provide an important new pathway to overseas markets for Bakken, western Canadian and other North American crude. The first would involve reversing the Capline Pipeline, which was built to transport crude north from the U.S. Gulf Coast to Midwest refiners; the second would make modest physical changes to the Louisiana Offshore Oil Port — better known as LOOP — to allow the crude import facility off the Bayou State coast to load crude onto ships, including Very Large Crude Carriers (VLCCs). Today we look at the new infrastructure and market forces that may finally spur Capline’s reversal and lead imports-focused LOOP to enable exports.
