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.
Higher crude oil and natural gas prices, improved efficiency in drilling and completion and other factors combined to give most U.S-based exploration and production companies (E&Ps) solid financial results in the first quarter of 2017 — a stark contrast to their performance in 2015 and 2016. Better yet, the turnaround is providing E&Ps with the optimism and wherewithal to significantly ramp up their planned capital spending this year and in 2018. It’s also giving them an opportunity to zero in on shale plays with low breakeven costs that will help them maintain profitability even if commodity prices stay flat or sag. Today we analyze the first-quarter financial results of a group of 43 U.S. exploration and production companies.
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.
One of the major target markets for Appalachian natural gas is the U.S. Southeast. More than 32 GW of gas-fired power generation units are planned to be added in the South-Atlantic states by 2020 and LNG exports from the Southeast are increasing. Of the 15.5 Bcf/d of takeaway capacity planned for Appalachia, close to 5 Bcf/d is targeting this growing demand. Despite the need, these pipeline projects designed to increase southbound flows from the Marcellus Shale have faced regulatory delays and setbacks. Today, we provide an update on capacity additions moving gas south along the Atlantic Coast.
For several years now, power generators and other major energy users in the Caribbean have been working to shift from diesel or fuel oil to alternative fuels — mostly natural gas delivered by ship as liquefied natural gas (LNG), but also propane. A few significant projects have advanced, and new infrastructure to receive LNG and propane has been put in place to support additional fuel imports into the region. But other projects have been delayed or even scrapped because of financial or regulatory troubles. Today we update the laid-back region’s efforts to wean itself off diesel- and fuel-oil-fired power.
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.
Rising crude oil production in the SCOOP and STACK oil and NGLs shale plays is driving the development of processing and natural gas pipeline capacity for associated natural gas volumes from the region. Earlier this month (Wednesday, May 3), Enable Midstream announced Project Wildcat, a 400-MMcf/d rich gas takeaway project. On the same day, SemGroup Corp. announced the Canton Pipeline to provide an initial 200 MMcf/d (and up to 400 MMcf/d) of capacity between the STACK play and its processing facility in northern Oklahoma. Enable last month also announced a firm shipper commitment on another of its takeaway projects — the Cana and STACK Expansion (CaSE). At the same time, late last month (on April 27), NextEra withdrew plans for its 1.2-Bcf/d Sooner Trails Pipeline. Today, we provide an update of the various projects vying to move associated gas from the SCOOP/STACK to downstream demand markets.
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.
Since 2013, nearly 3.0 Bcf/d of natural gas pipeline capacity has been added from Appalachia to the heavily populated, hard-to-reach demand centers along the East Coast. And another nearly 3.0 Bcf/d is in the works. The need for gas supply reliability in the heavily populated East, along with producers’ need to move their gas to market, is driving these expansions. But concentrated population centers, along with the geography, geology and regulatory environment of the area, all also make it tough and expensive for upgrading, expanding and developing the gas transportation system. Many of the proposed projects have been delayed or canceled as a result. Today, we provide an update on eastbound pipeline expansions from Appalachia.
Only a few years ago, pretty much all the natural gas flowing through pipelines in the southeastern U.S. was headed north to serve demand in the Northeast and the Midwest. But that’s all been changing — and fast. Gas production in the Marcellus/Utica has soared and now meets the needs of the Northeast and more. And, as LNG exports from the Gulf Coast ramp up and Southeast gas demand for power generation rises, more and more Marcellus/Utica gas is flowing south, raising the question of whether pipes in the Southeast can handle it all over the long term. Today, we discuss the findings of RBN’s work in preparing a study for the American Petroleum Institute (API) on the adequacy of regional gas pipeline infrastructure. RBN’s work discussed here is the current analysis being used to inform and develop stakeholder briefings. We anticipate API will release the final version in report form, after its completion.
U.S. exports of diesel and other distillates averaged 1.2 million barrels/day (MMb/d) in 2016, more than eight times their 2005 level and up slightly from 2015, another in a series of record-busting years for distillate exports. So far, 2017 looks like another winner. This year, though, a lot more distillate is being shipped south from Gulf Coast marine terminals to nearby Central America and South America, and less is being floated across the Atlantic to Western Europe. Today we consider recent trends in U.S. distillate exports and the significance of the export market to U.S. refiners.
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.
For years now, limited natural gas pipeline takeaway capacity has constrained gas production growth in the Marcellus/Utica natural gas shale plays in the Northeast. To fix that, a slew of pipeline projects were planned to relieve the constraints as regional supply began outstripping demand starting in 2014. Now, the region is on the verge of being unconstrained for the first time since the Shale Revolution hit Appalachia. Many of those projects have come online since then, and another 19 expansions totaling 15.5 Bcf/d are planned for completion by late 2019. If all goes as expected, this next round of projects should turn the Northeast market on its head again, as the capacity additions should start to outpace production growth. The problem, though, is that several projects have faced significant challenges in recent months, resulting in either cancellation or major delays. At the same time, Marcellus/Utica production growth has slowed dramatically in the past 18 months or so. In today’s blog, “In a Northeast Minute…Everything Can Change — An Update of Marcellus/Utica Takeaway Projects,” Sheetal Nasta begins a series looking at the status of regional takeaway capacity expansions.
After reducing capital expenditures by 70% in 2014-16, U.S. exploration and production companies (E&Ps) have collectively taken their foot off the brake and stomped on the gas, boosting 2017 capital outlays by an impressive 42% to kick-start production growth. At first glance, the move may seem somewhat reckless. After all, E&Ps just weathered a crisis caused by plunging oil prices partially through impressive capital discipline, and the price for benchmark West Texas Intermediate (WTI) crude oil has once again drifted below $50/bbl over concern that U.S. output may be rising too fast. But as we’ve learned from a new report by our friends at Bloomberg Intelligence, most major U.S. oil producers paired their increased investment with significant oil-price protection, aggressively snapping up hedges in late 2016 as oil prices were buoyed by the announcement of planned OPEC output cuts. Today we review BI’s examination of the efforts by many E&Ps to lock in $50/bbl-plus prices for much of their 2017 production.