Crude by rail (CBR) shipments from North Dakota to West Coast destinations peaked in January 2015 at 170 Mb/d – falling since then to average 140 Mb/d in 2015, January through May. The vast majority of these shipments have moved to four refineries in Washington State – providing a cheaper alternative to the Alaska North Slope (ANS) crude staple these refineries have run for decades. There is big potential to expand CBR shipments to West Coast Ports and to California but building the infrastructure has proven painstakingly slow. Today we discuss the long term fate of West Coast CBR.
Yesterday (August 3, 2015) Brent crude closed under $50/Bbl for the first time since January 2015. At that price expensive crude-by-rail (CBR) freight costs to the East Coast leave Bakken producers with netbacks not much over $30/Bbl. Yet CBR shipments to the East Coast were still over 400 Mb/d in May 2015 according to the Energy Information Administration (EIA). By 2017 there should be adequate capacity to get all Bakken crude to market by pipeline. But direct pipeline competition against rail to the East Coast is not expected until at least 2020. Today we look at the future of East Coast CBR.
Bakken crude-by-rail (CBR) volumes are down this year and pipeline shipments are increasing as production levels off in the wake of last year’s price crash. The trend is encouraged by lower price differentials between domestic and international crude as well as new pipelines coming online. Since 2012 a combination of rail and pipeline has given Bakken producers ample crude takeaway capacity but pipelines alone have not had sufficient capacity on their own. However, with production slowing down, pipeline capacity is catching up and by 2017 there should be enough pipelines to carry all North Dakota’s crude to market. Today we start a two part series asking whether pipelines can replace CBR from North Dakota.
Data from the Energy Information Administration (EIA) shows that inland barge movements between the U.S. Midwest and the Gulf Coast increased 10 fold between January 2011 and October 2013 to nearly 160 Mb/d in response to soaring crude production and pipeline congestion. Since then barge traffic on the Mississippi River (the main waterway between the two regions) plunged 80% to 27 Mb/d in April 2015 – the latest month reported. Today we explain why.
When the Apollo 13 astronauts realized their oxygen tanks were badly damaged, they famously said “Houston, we’ve had a problem.” Today, this phrase could well describe the U.S. oil and gas industry. The issue isn’t only today’s low prices, but also the industry’s resilience and its response to low prices. U.S. producers may have created a price ceiling for the world. Today we reflect on a new age of abundance in U.S. energy markets.
Oil-Weighted exploration and production companies (E&Ps) are slashing capital spending in 2015, as they need to regain control of their costs in today’s lower oil price environment. With robust oil prices over the past three years, these companies only posted middling profitability as capital and operating costs ate up much of their incremental revenue. The Large Oil Weighted E&Ps are cutting back less than the Small/Mid-Sized Oil Weighted E&Ps as they are more financially secure and have more ability to spend through the price cycle. The Small/Mid-Sized Oil Weighted E&Ps are focused on getting their spending in line with cash flows and to get to a point where they are self-funding their capital investment. Today we explore how each of the companies in the two oil-weighted peer groups is trying to resolve these issues.
The latest estimates from North Dakota show production edging up in March 2015 after a two-month decline. But the heady days are over for the moment - in the wake of lower crude prices - as even optimistic forecasts project flattened growth. Meanwhile combined rail and pipeline crude takeaway capacity out of North Dakota are already far higher than production – but new projects like the TransCanada Upland pipeline continue to be pitched to shippers. Today we describe how that could result in producers switching from existing routes.
Crude oil production is expected to be slowing down in U.S. shale basins in the wake of lower oil prices and drastic cuts in the number of working rigs. Most forecasts for future growth are far more conservative now. Yet new midstream pipeline projects continue to emerge. The latest proposal in the Bakken would add a minimum of 220 Mb/d of takeaway capacity sometime after 2018. At that point, between rail and pipeline, North Dakota takeaway capacity will be more than double RBN’s Growth Scenario production forecast – suggesting new pipelines will need to attract defectors from existing routes to market. Today we examine the rationale behind the proposed TransCanada Upland pipeline.
The Energy Information Administration’s (EIA) latest U.S. monthly crude production statistics published March 30th show January production down 135 Mb/d versus December 2014, the largest month-on-month decline since June 2011. There was an earlier warning sign from EIA. The agency’s Drilling Productivity Report (DPR) published March 9th predicted that production would decline in April in three major U.S. oil production regions – Bakken, Eagle Ford and Niobrara. Since oil and NGL prices crashed last fall, the market has been watching with bated breath for the first signs of a production slowdown. Certainly rig counts have nosedived amid producer budget cuts in 2015. But are we really seeing the beginnings of a long-term slowdown just yet? Was the DPR a harbinger of the January production decline? The clues lie within the DPR report. Today’s blog parses DPR methodology, assumptions and risks as well as contributing market factors to get to the bottom of what is driving those reported production declines.
Producers in the Bakken are making progress reducing the natural gas flaring that had put an unwelcome spotlight on the region. The fix, spurred in part by tightening regulations, is being made possible by the addition of new gas processing capacity and increased efforts to use “stranded” gas at the well-site. (A drilling slowdown associated with soft crude prices is providing an assist.) Today, we take a fresh look at what’s been happening on the flaring front in western North Dakota, where gas flares still light the nighttime sky.
The combination of crashing crude prices and freight costs for long distance transport to refinery markets is tightening pressure on Bakken crude producer break-even economics. There is plenty of more expensive rail transportation capacity and not enough cheaper pipeline capacity to carry all production to market. For the moment producers appear to be sticking to favored markets on the East and West Coasts that can only be reached by rail. New pipeline capacity is two years away. Today we review the big shifts in North Dakota crude transport options.
It’s been a big year for oil production from the Bakken formation in North Dakota with output passing the 1 MMb/d mark in April and expected to close out 2014 at 1.25 MMb/d. Crude netbacks (market price less transport cost from the wellhead) suffered during the first half of the year from narrowing coastal price differentials - denting the economics of crude-by-rail - the most popular option to get Bakken crude to market. Rail freight costs look set to increase in 2015 with new tank car regulations and requirements for wellhead treatment to remove volatile components. But those changes pale into insignificance compared to the recent crude price nosedive. That threatens to reduce producer revenues by billions of dollars in 2015 and puts the spotlight on higher transport costs to get crude to market from North Dakota. Today we look at the financial impact lower netbacks could have on Bakken producers.
If 2012 was “the year of the tank car” in North Dakota then 2014 could turn out to be the year when crude by rail economics turned sour for producers. New pipelines are coming online to deliver increased volumes of crude to the Gulf Coast with more projects on the drawing board. Safety issues and traffic congestion are raising the cost of rail freight. But the biggest challenge to rail is the pressure from narrowing crude price differentials between North Dakota and coastal markets. Producers can now get better returns shipping barrels by pipeline and in a falling price market they are more incented to make the switch. Today we explain why rail may be losing its edge.
New pipeline projects to take crude out of the Rockies are starting to make the map look like a spider’s web. The latest proposal comes from Spectra Energy – owners of the Express and Platte pipelines that ship crude from Hardisty to Wood River via Guernsey, WY. Spectra hope to build a pipeline carrying light sweet crude from Guernsey to the Midwest pipeline hub at Patoka. The project would bypass Cushing and push more light crude to the east with potential access to Midwest refineries or even the East Coast. Patoka is also poised to become an origination point for shipments to the Gulf Coast. Today we review the Spectra project’s chances in a crowded pipeline field.
The Denver-Julesburg (DJ) Basin of the Niobrara shale in Northeast Colorado is one of the hottest crude plays around at the moment. RBN expects DJ Basin crude production to nearly double from 235 Mb/d in August 2014 to 450 Mb/d by the end of 2019 – an increase of 215 Mb/d. That growing production has sparked an infrastructure-planning spree with 4 pipeline project announcements in the last two months that could add a whopping 600 Mb/d of takeaway capacity from the DJ to Cushing by 2017. On top of that rail-loading capacity is also expanding in the DJ. Today we describe the new midstream expansion plans.