U.S. oil and natural gas exploration and production companies, anticipating continuing low crude oil and natural gas prices, have been reshaping their portfolios to focus on a half-dozen top-notch resource plays whose production economics can hold up even through the roughest of patches. The biggest of these asset purchases and sales grab the headlines, but countless other, smaller deals are having profound effects too. Taken together, this piranha-like devouring of E&P assets in the Permian Basin, SCOOP/STACK and other key production areas is transforming who owns what in the plays that matter most, and positioning a select group of E&Ps for success. Today we review highlights from “Piranha!” —a just-released market study from RBN.
Posts from Housley Carr
The ability to increase the capacity of existing and planned crude oil pipelines with minimal capital expense has genuine appeal to midstream companies, producers and shippers alike. Enter drag reducing agents: special, long-chain polymers that are injected into crude oil pipelines to reduce turbulence, and thereby increase the pipes’ capacity, trim pumping costs or a combination of the two. DRAs are used extensively on refined products pipelines too. Today we continue our look at efforts to optimize pipeline efficiency and minimize capex through the expanded use of crude-oil and refined-product flow improvers.
Last week, crude oil prices dropped below $50/bbl, in part due to continued increases in U.S. crude oil inventories, and fell further over the next few days. Then yesterday, prices perked up by $1.14 to $48.86/bbl; again one of the factors was the weekly inventory number from the Energy Information Administration which showed inventories down by a fraction of a percentage point for the week. The market seems to react spontaneously to changes in that crude-stocks statistic. Up is bearish, down is bullish. These days even a very modest decline in inventories is bullish. But serious analysis requires a more detailed, more nuanced understanding of why crude oil inventories behave as they do. Were inventories driven up by higher production or lower refinery runs? By higher imports? By lower exports? The reasons behind the inventory change are more important than the change itself. Today we continue our series on the modeling of U.S. crude oil supply and demand, and the sourcing of input data used in those calculations.
New International Maritime Organization rules slashing allowable sulfur content in bunker fuels come January 2020 are expected to be a boon to complex refineries with coking units that can break residual high-sulfur fuel oil (HSFO) into low-sulfur middle distillates and other high-value products. The IMO rules also are expected to undermine the already shaky economics of many simpler refineries that don’t have cokers and are therefore left with a lot of residual HSFO. Today we conclude our blog series on the far-reaching effects of the new cap on bunker fuel sulfur content with a look at how the IMO rules will create winners and losers among refineries, and improve diesel refining margins.
The latest sharp drop in crude oil prices, which was blamed in part on unexpected gains in already record-high U.S. inventories, is a stark reminder of the importance of understanding and routinely calculating estimates of the oil supply/demand balance. Only by keeping up with the ever-changing relationship between crude availability and crude consumption—and by anticipating shifts in that relationship—can oil traders and others whose daily success or failure depends on crude pricing trends make informed decisions. Today we begin a blog series on the modeling of U.S. crude oil supply and demand, and the sourcing of input data.
Last year was the best for global LNG demand growth since 2011, and a combination of ample LNG supply, new buyers and relatively low prices suggest that demand will continue rising at a healthy clip in 2017. That’s good news not only for LNG suppliers, but for natural gas producers and for developers planning the “second wave” of U.S. liquefaction/LNG export projects. Before those projects can advance, the world’s current—and still-growing—glut of LNG needs to be whittled down, and nothing whittles a supply glut like booming demand. Today we discuss ongoing changes in the LNG market and how they may well work to the advantage of U.S. gas producers and developers.
The expectation that crude oil production in the Permian Basin will continue growing has set off a competition among midstream companies, a number of which are known to be developing plans for additional pipeline takeaway capacity out of what is clearly America’s top-of-the-charts tight-oil play. One of the biggest topics of conversation the past few days has been the plan by EPIC Pipeline Co. to build a new crude pipeline from the Permian’s Delaware and Midland basins to planned storage/distribution and marine terminals in Corpus Christi. Today we detail EPIC’s plan and explain the rationale for the pipeline’s route and destination.
Much tougher rules governing emissions from ships plying international waters soon will force wrenching change on the energy industry. Demand for high-sulfur fuel oil is expected to plummet; ditto for HSFO prices. Demand for low-sulfur distillates from the shipping industry will rise sharply, putting upward pressure on prices for marine gas oil, marine diesel oil and ultra-low-sulfur diesel. These demand and pricing shifts, in turn, will have a number of significant effects on refiners. Today we continue our series on the far-reaching effects of the International Maritime Organization’s (IMO) mandate to slash emissions from tens of thousands of ships starting in January 2020.
A number of the Bakken’s leading producers are talking up the shale play’s prospects for crude oil production gains in 2017—and especially in 2018—but we are still waiting on numbers that would prove that the play has truly turned a corner. What is crystal clear, though, is that the Bakken’s biggest takeaway project ever, the 470-Mb/d Dakota Access Pipeline to Illinois, is finally nearing completion and operation after a very public delay. When DAPL comes online this spring, it will further reduce crude-by-rail volumes out of the Bakken and should help to increase the odds that production in the play will begin to rebound in earnest. Today we update production and takeaway capacity in the nation’s third-largest crude-focused shale play.
A new international rule slashing allowable sulfur content in the marine fuel or “bunker” market will have profound effects on global demand for high sulfur fuel oil and low-sulfur middle distillates—and with that, major impacts on the price of those products, the demand for various types of crude, and the need for refinery upgrades. What we have in the making here is a refining-sector shake-up that will extend well into the 2020s. Today we begin a series on the rippling effects of the International Maritime Organization’s (IMO) mandate that, starting in January 2020, all vessels involved in international trade use marine fuel with sulfur content of 0.5% or less.
The production economics of the crude oil-focused SCOOP and STACK plays in central Oklahoma are among the best anywhere—in fact, only the Permian Basin’s numbers outshine them. But, as in the Permian, crude production in SCOOP and STACK can only grow if sufficient midstream infrastructure is in place to process and take away all of the associated natural gas the wells there produce. Processing and takeaway constraints aren’t big issues in SCOOP/STACK yet, but they will be soon. Today we discuss highlights from RBN’s new Drill Down Report on production growth and looming infrastructure constraints in two of the U.S.’s most promising shale plays.
A number of indicators suggest that the energy slump that started in the latter half of 2014 has bottomed out, and that happy days are here again (at least for now). Who would have thought back in the good ol’ days three years ago this month—when the spot price for crude oil was north of $100/bbl and the Henry Hub natural gas price averaged $5.15/MMbtu—that Friday’s $54 crude and $2.63 gas would be seen as anything but a catastrophic meltdown. But not so. The fact is that in 2017, producers in a number of basins can make good money at these price levels. Consequently, drilling activity is coming on strong. Crude oil production is up more than 500 Mb/d since October 2016 to 9 MMb/d, a level not seen in almost a year. And gas output has also been poised to rise, if only real winter demand had kicked in this year. What’s going on? Today we discuss the fact that what we have here, folks, is a rebound unlike any we’ve seen before.
The SCOOP and STACK plays in central Oklahoma have emerged as two of the most productive and cost-effective plays in the entire U.S. Rigs are returning, crude oil production is rising, and so is production of associated natural gas. Moreover, the RBN production economics model shows that SCOOP and STACK will continue to be attractive to drillers under all of our various price scenarios—even if crude were to slip back below $50 and natural gas goes back into the dog house, where it has been headed the past few days. Today we continue our look at the side-by-side Sooner State plays with a review of existing and planned gas processing capacity.
Anticipating renewed growth in natural gas and natural gas liquids production in the Marcellus and Utica plays, midstream companies active in the region are planning new gas processing plants and fractionators, as well as new NGL takeaway capacity and in-region NGL storage. And Shell Chemicals has made a Final Investment Decision to build a $6 billion, ethane-consuming steam cracker in western Pennsylvania by the early 2020s. In today’s blog, “Unleashed in the (North)East—New Gas Processing and Fractionation Capacity in Marcellus/Utica,” Housley Carr continues our series on on-going efforts by midstreamers and others to keep pace with NGL growth in the epicenter of U.S. gas and NGL production.
The Shale Revolution has caused big changes in U.S. crude oil production, in domestic flows of crude via pipelines, ships and rail tankcars, and in crude import volumes. Flow changes in particular have negatively affected the Strategic Petroleum Reserve’s ability to accomplish its two primary goals: protecting U.S. refineries from the worst effects of a major crude oil supply interruption, and—when called upon by the International Energy Agency—quickly injecting large volumes of crude into global markets. A fix now in the works would add Gulf Coast marine terminals dedicated specifically to moving SPR-stockpiled crude to those who need it, both within the U.S. and overseas. Today we conclude a two-part blog series on challenges and coming changes at the SPR.