Production volumes in the Alberta oil sands continue to inch up as production expansion projects sanctioned in better times — almost all of the projects small in scale — come online. However, several major pipeline projects remain on the drawing board; taken together, they would appear to provide far more pipeline takeaway capacity than the oil sands will need. Which raises two questions: how much incremental pipeline capacity is needed, and which pipeline project or projects are most likely to advance? Today we continue our series on stagnating production growth in the world’s premier crude bitumen area, the odds for and against a rebound any time soon, and the need (or lack thereof) for more pipelines.
Daily Energy Blog
Monday, 5/01/2017
The highly attractive production economics of the Permian’s multistacked, hydrocarbon-packed Delaware and Midland basins all but guarantee that the region’s output of crude oil, natural gas and natural gas liquids will continue rising—possibly at an even faster rate than what we’ve seen lately. That raises an all-important question: Will there be sufficient pipeline takeaway capacity in place to keep pace with all that growth? If there isn’t, some Permian producers will suffer from downward pressure on local prices—and that may cause them to have second thoughts about the big bucks they paid to gain access to the best Permian acreage in the first place. A production-growth forecast and a deep-dive assessment of existing and planned pipeline takeaway capacity are at the heart of RBN’s new Drill Down Report on the Permian. Today we provide highlights from the new report.
Monday, 4/24/2017
The Permian may be grabbing most of the energy headlines lately, but a noteworthy share of crude oil production growth the U.S. experiences over the next two or three years is sure to come from the Gulf of Mexico. There, far from the Delaware Basin land rush and the frenzy to build new Permian-to-wherever pipelines, a handful of deepwater production stalwarts are completing new wells — at relatively low cost — that connect to existing offshore platforms. Taken together, these projects are expected to increase the Gulf’s output by more than 300 Mb/d by the end of 2018. Today we look at the Gulf’s under-the-radar growth in oil output and the prospects for continued expansion there.
Sunday, 4/23/2017
The techniques used to wring increasing volumes of crude oil, natural gas and natural gas liquids (NGLs) out of shale continue to evolve, and as they do, producers are facing mounting costs for securing frac sand and for disposing of produced water from the wells. These costs are squeezing producer profits, and—in an era of sustained low hydrocarbon prices—sometimes even flip production economics from favorable to unfavorable. Today we continue our surfing-themed series on sand costs and water-disposal expenses with a look at how sand use in shale plays has evolved—and how these changes affect the bottom line.
Monday, 4/17/2017
In the past few years, producers in shale and tight-oil plays have made great strides in reducing their drilling costs and improving the productivity of their wells. But the trends toward much longer laterals and high-intensity well completions have significantly increased the volumes of sand being used—some individual well completions use enough sand to fill 100 railcars or more! An even bigger concern for many producers is the rising cost of disposing of produced water—that is, the water that emerges with hydrocarbons from these supersized wells. Today we begin a surfing-themed series that focuses on how the two key components of any beach vacation—sand and water—are impacting producer profitability.
Wednesday, 4/12/2017
Crude oil prices are up more than $5/bbl over the past couple of weeks, mostly due to Middle East tensions and the latest readings of OPEC tea leaves. U.S. markets have contributed little to the bullish trend, with crude oil inventories hanging in there at 533.4 million barrels, just under the all-time record hit last week. U.S. production is up almost 800 Mb/d since the low last summer and a whopping 550 Mb/d since the OPEC/NOPEC deal. That’s some decidedly bearish statistics. If these trends hold, the U.S. could completely offset the 1.2 MMb/d in OPEC production cuts in another six months. But that begs the questions, where exactly do these statistics come from, and how should they be interpreted? The first answer is simple: it is the U.S. Energy Information Administration. But where do they get the numbers? And what can we learn about the crude oil market through a better understanding of the sources and assumptions behind these numbers? That is our topic in today’s blog.
Sunday, 4/09/2017
The build-out of Houston-area crude oil storage and marine terminal capacity continues, and as it does, ship congestion in the Houston Ship Channel worsens. Which raises the question, why not develop more crude storage and marine docks outside the Ship Channel that still offers strong pipeline connectivity to crude production areas, the Cushing hub and Houston-area refineries—plus easier access to the open waters of the Gulf of Mexico? That’s a key premise behind Oiltanking’s first major Gulf Coast expansion since the February 2015 sale of most of Oiltanking’s assets in the region to Enterprise Products Partners. Today we discuss Oiltanking’s plan to add crude storage and a marine terminal in Texas City, TX.
Tuesday, 3/28/2017
On Friday, TransCanada finally secured a Presidential Permit for the U.S. portion of its Keystone XL pipeline, and the company committed to pursuing the state approvals it still needs to build the project. But three hard truths—crude oil prices below $50/bbl, the high cost of producing bitumen and moving it to market, and more attractive energy investments available elsewhere—have thrown a wet blanket on once-ambitious plans to significantly expand production in Western Canada’s oil sands, the primary source of the product that would flow through Keystone XL. Today we begin a series on stagnating production growth in the world’s premier crude bitumen area, the odds for and against a rebound any time soon, and the need (or lack thereof) for more pipelines.
Monday, 3/27/2017
According to Energy Information Administration data, the 26 refineries in the Midwest/PADD 2 region processed an average 3.6 MMb/d of crude oil in 2016—up 300 Mb/d from the 3.3 MMb/d refined in 2010. Over the same six-year period, production of light oil production in the region shot up by over 1 MMb/d, mostly from the prolific Bakken formation in North Dakota. Yet Midwest refiners did little to take advantage of the sudden abundance of “local” production, increasing instead their appetite for imported heavy crude from Western Canada by nearly 1 MMb/d—from 800 Mb/d in 2010 to 1.8 MMb/d in 2016. Today we explore the trend for PADD 2 refineries to run more heavy crude even as shale output surged in their backyard.
Sunday, 3/26/2017
U.S. crude oil production is back above where it was this time last year—at 9.1 MMb/d, 700 Mb/d over the low point last summer. Nearly 400 Mb/d of that surge has been since end-November when the OPEC deal was announced. So, in less than four months, U.S. producers have already taken one-third of the 1.2 MMb/d market share OPEC gave up. No doubt about it: The U.S. E&P sector is back. But not because prices are above $60 or $70/bbl. Instead, this recovery is being driven by rising productivity in the oil patch. And that makes it a whole different kind of animal than we’ve seen before, with implications for upstream, midstream, downstream and just about anything that touches energy markets. That’s the theme for our upcoming School of Energy—Spring 2017—“Back in the Saddle Again—Market Implications of the 2017 U.S. Oil and Gas Recovery” that we summarize in today’s blog.
Thursday, 3/23/2017
Despite OPEC’s production cuts, crude oil prices are still hovering just below $50/bbl, and there are certainly no guarantees that they won’t fall back to $40 or lower (at least for a while). So the survival of many exploration and production companies continues to depend on razor-thin margins, meaning that E&Ps need to trim their capital and operating costs to the bone. Lease operating expenses—the costs incurred by an operator to keep production flowing after the initial cost of drilling and completion—are a go-to cost component in assessing the financial health of an E&P. But there’s a lot more to LOEs than meets the eye, and understanding them in detail is as important now as ever. Today we continue our series on the little-explored but important topic of lease operating expenses.
Monday, 3/20/2017
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.
Wednesday, 3/15/2017
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.
Tuesday, 3/14/2017
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.
Sunday, 3/12/2017
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.
