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.
Daily Energy Blog
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 oil- and condensate-focused SCOOP and STACK shale plays in Central Oklahoma have been garnering the industry’s attention for their attractive producer economics, which are second only to the Permian among the crude oil shale plays. Rig additions in Oklahoma over the past several months are clearly targeting this 11-county area of the Anadarko Basin, and the RBN Production Economics Model projects production from the region will grow by 1.5 Bcf/d over the next five years. The increased drilling activity and expected production growth has piqued the interest of midstream companies looking to invest in infrastructure in the area. Given the increased output, is more takeaway capacity needed, and if so by when? Today we continue our look at the potential for takeaway constraints out of the SCOOP and STACK.
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.
U.S. natural gas exports drove a significant portion of overall gas demand growth in 2016 and are expected to continue being the primary demand driver over the next several years. Much of this export demand will be emerging along the Texas-Mexico border and at planned LNG export terminals along the southern Texas Gulf Coast. But production in the South Texas region is not expected to grow nearly as quickly or robustly as demand, setting the stage for supply constraints and premium pricing in the South Texas market and making the area a target destination for producers and pipeline companies. For example, on Wednesday, Enterprise announced the possibility of a new pipeline from Orla, TX, in the Permian Basin to Agua Dulce in South Texas. So how will all of this play out? Today, we continue our series analyzing the gas supply and demand balance in South Texas, this time with a look at the demand side and the resulting market balance.
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.
Natural gas production out of Oklahoma’s SCOOP and STACK plays has been resilient in the face of lower oil and gas prices and is expected to grow by about 1.5 Bcf/d over the next five years. But with the Marcellus/Utica increasingly competing for both pipeline capacity and demand markets outside the Northeast region, the question is where can and will the new SCOOP/STACK supply go? That will be dictated in large part by where demand is growing—primarily along the Gulf Coast—and where the price differentials are attractive. But flows also can be hindered or facilitated by another, preeminent factor: pipeline takeaway capacity. Today we explore the potential for takeaway constraints out of the SCOOP and STACK.
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.
There is a premium natural gas market developing in South Texas, where exports to Mexico could rise by more than 2.0 Bcf/d over the next four years and gas liquefaction and LNG export facilities are expected to add another 1.8 Bcf/d of demand to the market in that time. While gas production from the nearby Eagle Ford Shale is showing signs of at least a partial comeback and will help meet some of this new demand, the South Texas market may be heading toward being short supply in the next few years, resulting in higher prices there relative to surrounding markets. That would make the South Texas market an attractive destination for supply as far north as the Marcellus and Utica shales. In fact, there is a slew of proposed southbound pipeline projects extending deep into Texas along the Texas Gulf Coast for shippers to get their gas there. But how much incremental supply will be needed to balance the market? Today we begin a series analyzing the gas supply and demand balance in South Texas, starting with prospects for production growth out of the Eagle Ford Shale.
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 March 2017 CME/NYMEX Henry Hub natural gas futures contract has shed nearly 60 cents/MMBtu (17%) since February 1, 2017, and the rest of the 2017 curve has been slashed by an average 40 cents (12%) in that time. On February 1, prices for all 10 remaining 2017 futures contracts (from March to December 2017) carried $3 handles. Now, all but two contracts are below $3. Weather has been the primary driver of this shift. February 2017 is set to rank as the warmest February since 1970, after January 2017 also came in as one of the warmest in 40 years. Weather forecasts are also showing the warmth extending into March. These developments are signaling a more bearish 2017 than expected. Today, we continue our supply and demand update with a look at the 2017-to-date balance.
