Crude by Rail

Sure, there was at least some hope among Keystone XL’s supporters that President Biden might back away from his promise to kill the much-maligned crude oil pipeline project. After all, KXL developer TC Energy had done all it could to make the 1,210-mile project more palatable to the incoming administration by making Canadian First Nation groups partners in the project, reaching a favorable labor agreement with the four U.S. unions that would build the pipeline, and, most recently, committing to invest in renewable energy to power KXL’s pumps and other equipment. But it wasn’t enough, and now, with Biden’s decision to revoke the project’s Presidential Permit, it appears that the Alberta-to-Nebraska pipeline is all but dead, and that Western Canada will need to get by without its 830 Mb/d of southbound capacity. The looming question now is, what does that mean for Alberta’s producers — particularly those that have signed up for more than 500 Mb/d of space on KXL? Today, we discuss what’s ahead.

It’s been well-reported that crude oil pipeline capacity is getting maxed out in many basins across the U.S. and Canada. From Alberta, through the heart of the Bakken, all the way down to the Permian, pipeline projects are struggling to keep up with the rapid growth in some of North America’s largest oil-producing regions. Crude by rail (CBR) has frequently been the swing capacity provider when production in a basin overwhelms long-haul pipelines. While it is more expensive, more logistically challenging, and more time-intensive, CBR capacity is typically able to step in and provide a release valve for stranded volumes. But recently, CBR capacity has been tougher to come by and has taken longer than expected to ramp up. A key aspect of this issue is a new requirement for up-to-date rail cars. Today, we look at how new rail demands and uncertainty in domestic oil markets are combining to create a major hurdle for new CBR capacity.

Crude oil pipelines out of the Permian are filled to capacity and the differentials between crude in Midland and in Cushing and Gulf Coast destination markets are wide and likely to widen. That has spurred Permian producers and shippers to consider every possible option for moving incremental barrels out of the play, including two old short-term standbys: tanker trucks and crude-by-rail. Cost isn’t a major issue — the price spread and the Permian’s low break-evens will probably justify the higher expenses associated with trucking and railing crude. But that doesn’t mean that badly needed truck and rail capacity can appear with a poof as if by magic. No, even wads of cash may not be enough to quickly round up the hundreds — thousands? — of trucks and drivers that would be required to make a significant dent in the Permian’s takeaway shortfall. And developing brand new crude-by-rail terminals can take a year or more — too much time to address the play’s more immediate needs. Today, we continue our look at the frenzied efforts under way to move more Permian crude to market.

During the oil market’s downturn from mid-2014 through 2016, the Bakken Shale, primarily located in North Dakota, was at the forefront of the collapse. The Bakken rig count dropped from a high of 219 to a low of 24 as production fell by 300 Mb/d, or 24%. For many, it was time to write off the Bakken as a one-hit wonder. But as drilling productivity increased and prices rebounded, so did production. Crude oil output is again above 1.1 MMb/d and the rig count has doubled from its low point. Today, we begin a blog series on recent developments in Bakken production, well productivity and market pricing, and discuss RBN’s latest production forecast for the play.

The crude oil-carrying Dakota Access Pipeline (DAPL) has been up and running for almost six months now, creating new market dynamics in the Bakken. But these changes haven’t garnered all that much attention — they’ve been overshadowed by talk of Permian production growth, Gulf Coast pricing and Cushing pipeline capacity. Now though, with news of super-long three-mile laterals and increasingly positive producer sentiment, the Bakken is once again shifting into the limelight — and the 525-Mb/d DAPL from western North Dakota to Patoka, IL is center-stage. Today, we discuss DAPL’s effects on Bakken crude prices, market access, other takeaway pipelines and crude by rail.

The Shale Revolution changed everything about U.S energy markets, and in the process made forecasting the production and pricing of crude oil, natural gas and NGLs a heck of a lot harder. But we all learn from experience. In the early days of the Revolution, few could have predicted how quickly output would rise, how challenging it would be for pipeline takeaway capacity to keep up with production, or how successfully crude-by-rail would fill the gap – until that gap went away with the Revolution’s most recent phase. Comparing past forecasts to what actually happened is instructive though, and maybe––just maybe––today’s projections for the future are more informed than the forecasts of 2011 or 2013. In today’s blog we look at a recent presentation on forecasting lessons learned at RBN’s School of Energy earlier this month.

A few years back, crude-by-rail (CBR) emerged as the go-to fix that enabled pipeline-constrained shale regions to move fast-increasing volumes of oil to market. A total of 178 rail terminals were built or significantly expanded, with 99 loading terminals and 79 unloading terminals developed in the U.S. and Canada.  But changes in the market -- lower oil prices, slowing/declining production, new pipeline capacity -- have been challenging and undermining CBR.  Only about 20% of U.S. nameplate capacity is being used, and further declines in CBR volumes are expected, prompting serious questions about CBR’s future role.  Today, we discuss RBN Energy’s latest Drill Down Report, which examines CBR’s pros and cons, its evolution, and its current status and prospects.

Most of the crude by rail  (CBR) shipments to 4 refineries in Washington State are ex-North Dakota from where rail freight costs are over $10/Bbl. Bakken crude from North Dakota competes at Washington refineries with Alaska North Slope (ANS) shipped down from Valdez, AK. Back in 2012 ANS prices were more than $20/Bbl higher than Bakken crude – easily covering the rail cost. In 2016 so far the ANS premium to Bakken has averaged well below the $10/Bbl freight cost making CBR shipments uneconomic. But as we discuss today - Northwest refiners are still shipping significant volumes of crude from North Dakota.

According to the latest Energy Information Administration (EIA) monthly Drilling Productivity Report, crude production from the Niobrara shale in Colorado and Wyoming peaked at 491 Mb/d in April 2015 and is forecast to decline by ~100 Mb/d to 388 Mb/d through March 2016 – in response to falling crude prices and lower drilling activity. Meantime midstream companies are still building new pipeline capacity out of the region with the Saddlehorn and Grand Mesa projects set to add 350 Mb/d of takeaway capacity this year (2016). The pipeline build out has already caused a shift of crude shipments away from crude-by-rail (CBR) that peaked in December 2014. Yet as we describe today - rail terminals and infrastructure are still under construction in the region.

Crude prices are hovering around $30/Bbl making crude–by-rail (CBR) transport an expensive option for hard pressed producers looking to conserve cash – especially where pipeline alternatives are available. The crude price differentials that once justified shipping inland crude to coastal destinations by rail have all but disappeared. In November, 2015 pipeline shipments exceeded rail out of North Dakota for the first time since 2011 and by 2017 available pipeline capacity out of the region should exceed producer’s needs. In the circumstances, rail shipments would appear to be living on borrowed time but as we describe today - some North Dakota rail shipments are continuing in spite of the poor economics.