Crude Oil

Sunday, 04/21/2019

Crude oil production in the Permian Basin is now approaching 4 MMb/d, and with more than 2 MMb/d of new pipeline takeaway capacity out of the resource-rich play set to come online over the next 12 months, there soon will be plenty of room for more production growth. To efficiently transport crude to takeaway pipes, however, producers and shippers need ever-growing networks of gathering systems in the Permian’s sweet spots where much of the drilling and completion activity is occurring. Ideally, these systems offer their users a high degree of optionality — that is, interconnections with multiple takeaway pipelines to different markets — so they can capture the best prices for their oil. Today, we continue our review of major gathering networks in the Permian with a look at Reliance Gathering’s nearly 250-mile system in the Midland, TX, area.

Wednesday, 04/17/2019

Only a few months after major crude oil takeaway constraints out of the Permian Basin caused price spreads to widen, the pipeline network serving the U.S.’s most prolific shale play may be on the brink of becoming overbuilt. We’ve already seen a number of new expansions and pipeline conversions completed in the past six months, and construction is underway on another 2 MMb/d of new pipeline capacity scheduled to come online between now and the first quarter of 2020. Beyond that, a few remaining projects have been proposed but have not yet reached final investment decisions. No midstream group wants to build a pipeline that will be half full, and no producer wants to make a 10-year commitment to a pipeline if there are going to be plenty of other options available. So who blinks first? In today’s blog, we review the Permian pipeline projects that are still on the fence and examine what factors will determine whether they end up being a “go” or a “no.”

Tuesday, 04/16/2019

Nowadays, the hydraulic fracturing of a typical Permian well with a 10,000-foot lateral requires about 12,500 tons of frac sand — enough sand to fill more than 500 large sand trucks. That sand needs to be at the ready — delivered, offloaded, stored, and set for blending and use. If it’s not, the well completion and the start of production would be delayed or the hydraulic fracturing process would be shut down after starting — a mortal sin in the shale world. With reliable, seamless access to frac sand at the well site being so critical, E&Ps and their pressure pumpers are understandably doing all they can to optimize their “last-mile” sand logistics. This involves everything from minimizing truck-delivery congestion to maximizing the speed at which sand is transferred from truck to storage, as well as the type of storage used. It’s all much more high-tech than you might think. Today, we conclude our series with a look at the latest in last-mile logistics, which can account for as much as one-third of the total delivered cost of sand.

Monday, 04/15/2019

The rapid development of the Permian’s vast hydrocarbon resources that we expect will continue through the 2020s and beyond can’t happen if there’s insufficient gathering-pipeline infrastructure in place to transport crude from well sites to takeaway pipelines. Similarly, the favorable pricing that Permian producers hope to receive for their crude oil is possible only if their gathering systems are interconnected to two or more long-haul, big-bore pipelines that offer them some serious destination optionality. The need for new gathering pipes with multiple links to Gulf Coast- and Cushing-bound takeaway pipes is the driving force behind the Beta Crude Connector, a planned 100-mile-plus pipeline network in the heart of the Permian’s Midland Basin that was unveiled on Monday (April 15) by a joint venture of Concho Resources and gathering specialist Frontier Energy Services. Today, we kick off a new blog series on crude-gathering projects in the Permian with a look at the Concho/Frontier plan.

Sunday, 04/07/2019

Crude differentials in the Permian are getting squeezed. The spread between Midland and WTI at Cushing widened out to near $18/bbl at one point in 2018, when pipeline capacity was scarce. But that same spread averaged a discount of only $0.25/bbl in March 2019. Differentials between Midland and the more desired sales destination at the Gulf Coast are also in a vise. What gives? Production in the Permian continues to climb, but the rapid pace of growth we saw in 2018 has slowed down a bit lately, with fewer rigs in service and fewer new wells being brought on each month. More importantly, we’ve seen several new pipeline expansions and pipeline conversions come online in bits and bursts — in some cases, ahead of schedule — and this new chunk of pipeline space has compressed Midland pricing. In today’s blog, we begin a series on Permian crude takeaway capacity and differentials, with a look at the handful of new projects that have come online in the past few months and what has happened to Permian prices as a result.

Tuesday, 04/02/2019

A primary focus of E&Ps during the Shale Era has been driving down the cost of drilling and completing wells — doing so lowers producers’ break-even costs and increases their profitability. With the volumes of frac sand being used in the Permian and many other plays having grown dramatically in the past five years, a big push is on not only to minimize the cost of the sand itself, but to maximize the efficiency of sand delivery and sand management at the well site. All this has been spurring E&Ps to assume responsibility from oilfield service companies for the frac sand supply chain — anything from directly sourcing the sand to managing “last-mile” logistics. Today, we continue our series on the rapidly changing frac-sand world, this time concentrating on producers’ growing involvement in sand procurement and management.

Sunday, 03/31/2019

Some shipowners plan to comply with the IMO 2020 deadlines for limiting sulfur in ship emissions by installing scrubber devices to clean the exhaust generated by burning less expensive high-sulfur bunker fuel. For many, this may work out to be more economical, at least in the interim, than using more costly IMO 2020-compliant fuel with sulfur content of no more than 0.5% or converting the vessel to run on an altogether different fuel such as liquefied natural gas. However, narrowing “sulfur spreads” this year have put that compliance strategy at risk by tripling the time it would take for shipowners to recoup their scrubber investments. Today, we continue an analysis of the changing economics of scrubber installation in the run-up to IMO 2020.

Monday, 03/25/2019

Crude production is at all-time highs in the Bakken and the Niobrara, and the latest pipeline-capacity expansions out of both regions have been filling up fast. At the same time, producers in Western Canada are dealing with major takeaway constraints and are on the hunt for still more pipeline space. Midstream companies are trying to oblige, proposing solutions like a major Pony Express expansion or a new Bakken-to-Rockies-to-Gulf Coast fix — the Liberty and Red Oak pipelines — that could help address all of the above. The catch is that, with multiple producing areas funneling crude along the same general eastern-Rockies corridor and the outlook for continued production growth uncertain, how’s a shipper to know whether to sign a long-term deal for some of the incremental pipe capacity now being offered? Today, we consider the need for new takeaway capacity, the potential for an overbuild scenario, and what it all means for producers and shippers.

Sunday, 03/24/2019

Over the past three years, the U.S. frac sand market has been transformed. Demand for the sand used in hydraulic fracturing is more than twice what it was in early 2016. Dozens of new “local” sand mines have come online, slashing the need for railed-in Northern White Sand in the Permian and a number of other fast-growing plays. Frac sand prices have fallen sharply from their 2017 highs. And exploration and production companies, which traditionally outsourced sand procurement and “last-mile” sand logistics to pressure pumpers and other specialists, are taking a more hands-on approach. It’s a whole new world. Today, we continue our series on the major upheavals rocking the frac sand world in 2019 with a look at the development of local sand sources in the Eagle Ford, SCOOP/STACK and the Haynesville.

Thursday, 03/21/2019

Enbridge is taking a serious look at converting its Southern Lights pipeline, which currently transports  diluent northwest from Illinois to Alberta, to a 150-Mb/d crude oil pipe that would flow southeast. The potential reversal of Southern Lights is made possible by the facts that Western Canadian production of natural gasoline and condensate — two leading diluents — has been rising fast, and that demand for piped-in diluent from the Lower 48 is on the wane. Alberta producers could sure use more crude pipeline capacity out of the region — and getting crude down to the U.S. Midwest would give them good access to a variety of markets. With Western Canadian diluent production increasing fast, maybe Kinder Morgan’s Cochin Pipeline, another diluent carrier, could also be flipped to crude service later on. Today, we consider how Southern Lights’ conversion/reversal might help.

Monday, 03/18/2019

The U.S. frac sand market has been turned on its head. Over the past three years, demand for the sand used in hydraulic fracturing has more than doubled, dozens of new “local” sand mines have been popping up within the Permian and other fast-growing plays, and frac sand prices have fallen sharply from their 2017 highs. The big changes don’t end there. Exploration and production companies (E&Ps), who traditionally left sand procurement to the pressure pumping companies that complete their wells, are taking a more hands-on approach. And everyone is super-focused on optimizing their “last-mile” frac sand logistics — the delivery of sand by truck, plus unloading and storage of sand at the well site — with an eye toward minimizing completion costs and maximizing productivity. Today, we begin a blog series on the major upheavals rocking the frac sand world in 2019.

Sunday, 03/17/2019

Last year, the impending implementation of International Maritime Organization’s rule mandating the use of lower-sulfur marine fuels starting January 1, 2020, widened the price spread between rule-compliant 0.5%-sulfur bunker and the 3.5%-sulfur marine fuel that has been a shipping industry mainstay. Traders’ thinking was that demand for high-sulfur bunker would evaporate in the run-up to IMO 2020, as the new rule is known. But since early January, the spread between low- and high-sulfur fuel at the Gulf Coast has narrowed from nearly $11/bbl to less than $2/bbl. The culprit is a shortage of heavy-sour crude caused by a number of factors. Today, we begin a two-part series on low-sulfur vs. high-sulfur fuel and crude values as IMO 2020 approaches.

Wednesday, 03/06/2019

By mid-year, Enbridge plans to initiate an open season for long-term, firm capacity on its existing 2.8-MMb/d Mainline crude system from Western Canada to the U.S. Midwest starting in mid-2021. Securing a sure way for Western Canadian heavy-crude producers to export crude from the Alberta oil-sands region — combined with additional southbound pipeline capacity from the Midwest to the Gulf Coast, would give Texas and Louisiana refineries an alternative to using overseas imports and would boost crude volumes being shipped from existing and planned export terminals. Today, we conclude our series on the pipeline’s contracting plans with a look at the impact of a straight-shot, joint-tariff pipe as well as joint pipe-barge transportation solutions from the oil sands to the Gulf Coast. 

Sunday, 03/03/2019

Increasing U.S. shale oil production has benefitted many U.S. refineries, but along the Gulf Coast, the primary beneficiaries have been in Texas. As production increased in the Permian and Eagle Ford plays, new pipelines were built to supply refinery centers in Corpus Christi, Houston, and Beaumont/Port Arthur. In contrast, the availability of shale crude by pipeline to refineries in Southeast Louisiana has lagged. However, new pipeline capacity to the crude hub in St. James, LA, is about to change the dynamic in a major way. Today, we continue our series on St. James by discussing the Bayou State’s refinery infrastructure and how new pipelines could impact refinery crude slates.

Wednesday, 02/27/2019

The U.S. midstream sector has been on a development binge the past few years, mostly in an effort to catch up — and then keep up — with production growth in the Shale Era’s two premier plays: the Marcellus/Utica in the Northeast and the Permian Basin in West Texas and southeastern New Mexico. What’s sometimes overlooked, however, is that significant numbers of new pipelines, processing plants and other key assets are being built in smaller, lower-profile production areas. The Niobrara’s Denver-Julesburg and Powder River basins are cases in point. Exploration and production activity in the D-J in particular has been soaring, and the resulting gains in crude oil, natural gas and NGL output has been stressing the region’s hydrocarbon-related infrastructure, thus spurring the development of new processing plants and pipelines. Also, interest in the Powder has been renewed — production there has been rebounding after crude-production ups and downs and gas-production declines through the 2010s. Today, we discuss highlights from RBN’s new Drill Down Report on the Niobrara production region.