The accelerating trend toward high-intensity completions in the Permian, SCOOP/STACK, Marcellus/Utica, Haynesville and other key shale plays is sharply increasing demand for frac sand. As a result, there's upward pressure on sand prices and there are shortages of certain grades of sand that may continue into 2018. There is also increased interest in developing sand mines near production areas. It’s important to remember, though, that (1) there’s no evidence that sand-supply issues will seriously curtail drilling and completion activity, and (2) higher sand costs can be offset by the production gains that usually come from using a lot more sand. Today we continue our surfing-themed series on sand costs and water-disposal expenses with a look at the forecast for 2017-18 demand for frac sand, sand pricing trends, efforts to develop regional sand supply sources and the bottom-line upside of high-intensity completions.
Today OPEC convened in Vienna, expecting to extend production cuts for another nine months beyond June 30. Both the OPEC and NOPEC countries have generally kept to their commitments since January, which has been extremely good news for U.S. producers; they are enjoying higher prices, steadily improving economics and above all, the opportunity to capture market share from OPEC/NOPEC. Since the deal was announced this past November, U.S. production is up 600 Mb/d — about half of OPEC’s promised 1.2 MMb/d cut — and at this rate U.S. producers will have grabbed all of OPEC’s forgone market share by the end of the year. Put simply, the U.S. has taken on a leading role in international oil markets, and as a result it’s now more important than ever to understand on a more granular and real-time level what’s going on in U.S. crude production, imports, exports and inventory. In today’s blog we examine how U.S. producers have been profiting from OPEC/NOPEC efforts to curtail worldwide supply and prop up prices, and how RBN’s new weekly report, “The Gusher,” tracks the key factors affecting U.S. crude.
Over the past five years, the Corpus Christi area’s ability to refine or ship out crude oil has increased substantially, driven initially by rising production in the Eagle Ford play in South Texas — growth that has since subsided. Now, Corpus is preparing for a coming onslaught of crude from the red-hot Permian, whose producers see the coastal port as the preferred destination for their light crude and condensates. Today we continue a blog series on Corpus Christi’s crude-related infrastructure with a look at what’s already there and how storage and marine-terminal upgrades made over the past few years will be coming in handy.
Rising crude oil production in the Permian and the desire of many producers to get that oil to refineries and marine terminals in Corpus Christi has spurred interest in developing more than 1 million barrels/day (MMb/d) of new Permian-to-Corpus pipeline capacity by 2019. That raises the question of whether the Sparkling City by the Sea is prepared to receive and store all that crude — plus oil from the rebounding Eagle Ford play — and either refine it or load it onto ships. Today we begin a blog series on the potential flood of crude oil from the Permian’s Delaware and Midland basins into South Texas’s largest port and refining center, and how refiners and midstream companies are planning to deal with it.
For the first time ever, a Very Large Crude Carrier (VLCC) carrying Bakken crude has sailed from the Gulf of Mexico to Asia, and more may follow. With the startup of the Dakota Access Pipeline set for June 1, Bakken producers are only days away from gaining easier, cheaper pipeline access to the Gulf Coast, and are looking for new markets. Asian refineries are willing to pay a premium for Bakken-type crudes, and want other types of U.S. crude as well. And every 18 hours or so, a VLCC arrives at the Louisiana Offshore Oil Port—the only U.S. port capable of handling the mammoth vessels—offloads crude and leaves LOOP empty because the port is currently an import-only facility. Today we consider the potential for transporting more light, sweet crude to Asian refineries on VLCCs, either via ship-to-ship transfers or by reworking LOOP to enable exports.
Permian crude oil production and pipeline takeaway capacity out of the region are in a horse race —it’s a close one too, and the stakes are high. Twice in the past few years, Permian production growth has outpaced the midstream sector’s ability to transport crude to market, resulting in negative price differentials that cost many producers big-time. Now, thanks to increased drilling activity and producers’ heightened ability to wring more out of the play’s multistack formations, Permian production is expected to rise by at least another 1.5 million barrels/day (MMb/d) by 2022 —a 60%-plus gain over five years —raising the threat of another round of major price hits, maybe as soon as later this year. Today we continue a blog series on the challenges posed by rapid production gains in the hottest U.S. shale play.
Crude oil production in the Permian’s Midland and Delaware basins continues to rise, and producers in the red-hot shale play are hoping there will be enough pipeline takeaway capacity to handle all that growth. This is serious stuff—the Permian’s success the next few years will depend to a considerable degree on whether producers and the midstream sector can avoid the major constraint-driven price differentials between the Midland, TX hub, and destination markets like the Gulf Coast and Cushing, OK, that already have hit the Permian twice this decade. Today we discuss the prospects for another round of takeaway/price-differential trouble in the Permian as soon as late 2017/early 2018 and again in 2020-21.
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.
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.
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.
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.
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.
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.
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.
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.