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.
Crude production from the Denver Julesburg (DJ) and Powder River Basin (PRB) plays in the Niobrara shale in Colorado and Wyoming is up 260 percent to 361 Mb/d since January 2012 and is expected to double again by the end of 2019. Takeaway capacity is expanding but is complicated by crude streams travelling through the region from Canada and North Dakota. Rising condensate production also presents a challenge to midstream companies. New pipeline proposals to expand takeaway from the DJ by as much as 500 Mb/d have recently surfaced – suggesting that local producers are looking to secure capacity. Today we look at recent and planned expansions to Niobrara takeaway capacity.
Two weeks ago (August 21, 2014) Plains All American announced their proposed “Diamond” crude pipeline project from Cushing, OK to Memphis, TN that will feed the Valero Memphis refinery starting in late 2016. The new pipeline will provide more direct access from Cushing to supplies of the light sweet crude this refinery processes that are being produced these days in the Williston, Denver Julesburg, Permian and Anadarko basins. Presumably the Diamond pipeline will replace existing arrangements where crude is shipped up the Capline pipeline to Memphis. That development looks to be another nail in the coffin for the northbound Capline crude trunk route between St James and Patoka, IL. Today we discuss the proposal and its consequences for Capline.
Enbridge own and operate the longest liquids pipeline system in North America extending from Fort McMurray in Alberta to Montreal in Eastern Canada and south through the US Midwest to Freeport on the Texas Gulf Coast. Although the major purpose of the pipeline is to deliver heavy western Canadian crude, it also carries light crude to eastern Canada and the US Midwest. Projects underway that are expected to be completed at the end of 2014 will expand flows of light crude to the east by 400 Mb/d. Today we continue our series reviewing the Enbridge initiatives with the Light Oil Market Access (LOMA) projects.
A study released yesterday (August 4, 2014) by the North Dakota Petroleum Council (NDPC) details the final results of work they commissioned to extensively sample and test North Dakota crude oil. The goal was to establish the quality characteristics of Bakken crude oil to determine if it is more risky to transport by rail than other crudes. The results show Bakken crude to be similar to other light sweet crudes, to be consistent across the producing region and that it meets all the current hazardous materials transportation requirements. Today we review the report’s findings.
No, we aren’t talking about Colorado’s recent legalization of the “wacky weed”, but rather the high that the rush of light crudes is bringing to the refining industry in PADD IV, the Rockies region. While John Denver’s famous lyrics spoke of the magic of the Rocky Mountains, regional refiners have found elation in recent years as both domestic and readily accessible Western Canadian production increased, stranding crude supplies, putting downward pressure on prices and lifting their margins sky high. Today we examine how this has impacted the economics of the region and incentivized investment.
The latest North Dakota Pipeline Authority (NDPA) data for April 2014 shows crude production in that State finally crossing the 1 MMb/d mark. That threshold was finally crossed after producers recovered from a harsh winter that shut in production and constrained new drilling. But while production continues to grow and is expected to reach 1.7 MMb/d by the end of 2019, producer crude takeaway preferences appear to be changing. NDPA data shows an 8 percent reduction in rail shipments out of North Dakota since November 2013. Today we investigate the shift away from rail transportation.
There hasn’t been a major new refinery built in the lower 48 since 1976. Now, no less than 5 projects to build new oil refineries are on the drawing boards in North Dakota. These projects are really “micro” refineries since they all have 20 Mb/d capacity compared to the 128 Mb/d national average of operating US refineries (source: Energy Information Administration - EIA). The projects all aim to take advantage of a shortage of refined products in North Dakota – especially diesel – as well as abundant supplies of crude from the Bakken shale. Today we review their progress.
Last week US crude oil production reached 8.4 MMb/d – its highest level since October 1986 – up 50 percent since the start of 2011. The engines of growth are Texas and North Dakota and within those states, horizontal drilling in tight oil shale are generating the most exciting results. And while production is soaring, proved reserves are increasing even faster – laying the groundwork for continued output. Today we look at past, current and future US crude production growth.