Bakken crude transport options after the crash

Sandy Fielden for RBN Energy

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.

At the end of December we provided an update on crumbling crude netbacks (crude selling price minus transport costs back to the wellhead) for North Dakota Bakken producers, following the price crash in the second half of 2014 (see Boom Clap The Sound of My Netback). Since then US benchmark crude West Texas Intermediate (WTI) prices have fallen below $50/Bbl – meaning the situation for crude producers has gotten worse. With North Dakota located in the middle of nowhere, much of the crude has to travel long distance to coastal markets where most refineries are located. In the absence of adequate pipeline capacity producers have used more expensive rail transport to get Bakken crude to refineries on the East and West Coast. That made sense back in 2012 when pipelines were highly congested and crude prices at coastal locations were at a premium. Today cheaper pipelines should be the preferred option but rail is still the dominant method of transport to market. If production stays at current levels or increases, there isn’t enough capacity available anyway to ship all North Dakota production by pipeline. As a result, some barrels will still be shipped using more expensive rail options – further pressuring producer returns. Relief - in the shape of new pipelines - is still two years away - if those pipelines ever get built. Meantime more crude continues to be transported by rail than pipeline in-spite of the higher cost and resulting lower producer netbacks.

Taken together, available capacity on both rail and pipeline out of North Dakota today is more than enough to handle current and projected crude production. Figure #1 shows crude production (actual and forecast) and the transport balance out to the end of 2019. Before we get to the transportation - as is to be expected in the post-price crash world - we first need to clarify the crude production forecast in this chart. The actual production data (light blue shading) is as reported by the North Dakota Pipeline Authority (NDPA) up until November 2014. The forecast (purple shading) is based on RBN’s high growth scenario where resilient production keeps volumes growing for the next two years  - at which point demand responds to low prices and U.S. benchmark West Texas Intermediate (WTI) prices return to the $80/Bbl range by 2017. In this scenario there is no interruption in shale production growth. [We have also developed two alternatives to the growth scenario called the “cutback” and “contraction” scenarios that reflect lower production levels based on WTI prices only rebounding to $70 or $60 by 2020. We will provide more detail about these scenarios in future blogs.] Suffice to say, that in the case of Bakken crude production - as for other shale basins - growth is likely to slow down in a lower crude price environment and if that turns out to be the case then the forecast in Figure #1 is on the high side. 

Figure #1

Source, North Dakota Pipeline Authority, RBN Energy

Now back to the transportation in Figure #1. The red line represents available pipeline capacity (actual and forecast) as well as refinery crude consumption. You can see that pipeline capacity is increasing over the period but has been below production since 2011 and is not expected to come close to meeting crude forecast output until 2017. About 200 Mb/d of pipeline takeaway capacity was added last year in North Dakota. In May 2014 the Plains Bakken North pipeline added 40 Mb/d of capacity flowing north to an interconnect with the Enbridge mainline from Canada to Superior, WS. During 4Q 2014 the Butte Loop expansion added 100 Mb/d of pipeline capacity west and south to Guernsey, WY and in December the Hiland Double H pipeline added another 50 Mb/d of capacity from Dore, ND to Guernsey. [Hiland was recently acquired by Kinder Morgan for $3 Billion.] Also in December 2014 the 20 Mb/d Dakota Prairie refinery – a 50/50 JV between Calumet Specialty Products and MDU Resources began processing Bakken crude in Dickinson, ND although cold weather and technical problems have pushed back full production until at least April 2015. These additions leave total pipeline and refinery capacity at the start of 2015 close to 800 Mb/d – about 400 Mb/d short of total crude output (1.2 MMb/d) – meaning that at least 400 Mb/d of North Dakota crude production has to use rail transportation if all the pipelines are fully utilized (which they are not). If production increases at all - with no new pipeline additions expected online before 2017 - more barrels will end up using rail.

The green line in Figure #1 (shown cumulative, stacked on top of pipeline and refinery capacity) represents North Dakota rail loading capacity. Despite higher freight costs and deteriorating rail netbacks, midstream companies are still building rail load terminals. During 2014 about 100 Mb/d of capacity was added in North Dakota – mostly expansions to existing facilities. Another 330 Mb/d is expected online by the end of 2016 including two large terminals. The first of these is the Northstar Transloading terminal located just over the border from North Dakota in Fairview, MT that came online at the end of 2014 and will ramp up to 180 Mb/d during 2015 and the second is the Phillips 66 and Paradigm Energy Ventures terminal at Palermo, ND expected online in Q1, 2016 with 100 Mb/d loading capacity. Even without these two new terminals, the NDPA estimates total year-end 2014 rail loading capacity at about 1.3 MMb/d – enough to carry all the crude produced in North Dakota if required. 

For the moment then, North Dakota producers have a choice between plenty of rail capacity and less pipelines than would be needed to carry all their output. We don’t know exactly how much rail is currently being used versus pipeline but NDPA estimates for November 2014 (latest data) indicate that rail carried 59% of total Williston Basin crude to market – including South Dakota, Montana and some Canadian production. Applying that percentage to just North Dakota production gives us over 700 Mb/d meaning by that measure rail is the dominant mode of transport today. Why is that so when pipelines offer lower freight costs and better netbacks?

There are at least a couple of reasons.  One is because producers made commitments to rail terminals to get them built, and therefore are obligated to pay transport costs whether they use the terminal or not.  In this case the costs are viewed as ‘sunk’, and therefore are usually ignored in the decision to use the terminal or not.  The other, related reason is because  a great deal of Bakken crude is headed to refineries on the East and West coasts where there are no pipeline alternatives to rail. Refiners on the East Coast in particular have invested in rail tank cars and unloading infrastructure meaning they are committed to continue purchasing Bakken crude – for the moment. Pipeline routes from North Dakota to the Midwest and the Gulf Coast deliver Bakken crude into a far more competitive situation - up against similar light sweet crudes produced closer to market in the Permian and Eagle Ford basins. Given sunk costs on rail terminals, Bakken producers are using their rail capacity to move to the East and West coast markets rather than fighting it out with crudes closer to the Gulf coast.

By 2017 another 680 Mb/d of new pipeline takeaway capacity could be coming online in North Dakota in the shape of two big projects currently in the planning and permitting phases. Although it is hard to predict the fate of any pipeline proposal in the current price environment these projects do appear to have shipper support to get built. That puts them ahead of one project cancelled in December 2014 – the Enterprise Products Partners proposed 340 Mb/d Bakken to Cushing pipeline, which failed to attract sufficient shipper commitment to justify the investment. The first of the two projects still on the table is the longest lasting initiative – the Enbridge Sandpiper pipeline – a planned 230 Mb/d expansion of that company’s existing takeaway capacity on the 210 Mb/d North Dakota Pipeline system that carries crude to the Enbridge mainline at Clearbrook, MN. We have previously detailed the Sandpiper pipeline project (see The Night They Drove Old Dakota Express Down) that has been delayed by permitting issues and is now expected online in 2017. Sandpiper does appear to have shipper support including a 37.5 % investment from anchor customer Marathon Petroleum. Producers using Sandpiper will have access to Midwest refinery markets via Flanagan, IL and Patoka, IL as well as Gulf Coast markets via Cushing and the Enbridge/Enterprise JV Seaway pipeline. In terms of market access however, Sandpiper does not offer Bakken producers access to any new destinations that they cannot get to on existing pipelines – just more capacity.

Figure #2

Source: Energy Transfer Partners

The second pipeline takeaway project on the drawing board in North Dakota is the 75:25 joint venture between Energy Transfer Partners (ETP) and Phillips 66 to develop the previously announced Dakota Access Pipeline (DAPL) and Energy Transfer Crude Oil Pipeline (ETCOP). We posted a blog about an earlier iteration of this project in March 2014 (see Once, Twice, Three Times A Pipeline). The 450 Mb/d DAPL is proposed to run from the Bakken/Three Forks production area in North Dakota to Patoka, IL (see map in Figure #2) and the ETCOP pipeline (a conversion of the Trunkline gas pipeline) will run from Patoka to ETP’s crude terminal at Nederland, TX on the Gulf Coast (see Million Barrel Quarter for more on Nederland). If these projects proceed as planned the two pipelines would come online at the end of 2016.The DAPL pipeline would provide Bakken producers with access to Midwest refineries via Patoka and ETCOP would provide access to Texas Gulf Coast refineries via Nederland. Like the Sandpiper project, the ETP and Phillips 66 pipelines are supported by shipper interest – including Phillips 66 who is developing a midstream crude gathering system in North Dakota that will feed into the DAPL. Phillips also recently purchased (October 2014) the Chevron crude and products terminal at Beaumont, TX that is located adjacent to ETP’s Nederland terminal. ETP and Phillips subsequently announced an open season in November 2014 for a pipeline connecting their Nederland and Beaumont terminals with Lake Charles, LA and St. James, LA – that would (if built) provide access to Louisiana Gulf Coast refining capacity. We will provide more information on this project in a future blog but if built it would provide Bakken producers with more direct access to eastern Gulf Coast refineries by pipeline than they have had so far.

Commentary
The future of these pipeline projects is likely to depend on continued increases in Bakken production over the next two years and that in turn will be driven by the oil price environment. Given the excess of rail and pipeline takeaway capacity over production in North Dakota today, one could argue that new pipeline capacity is a luxury that will only be supported by higher oil prices. If oil prices stay low then producers may not be willing to make long term shipping commitments to new pipelines – especially if rail alternatives are operating today – even if they are more expensive. Back in 2012 rail transport was an “upstart” option in North Dakota that upset conventional thinking about crude transportation and bypassed pipelines. Today rail is the incumbent and midstream operators could have trouble convincing producers to make long-term commitments to pipelines. That’s just how quickly things change in the oil patch. 

About the author
Sandy Fielden serves as Director Energy Analytics for RBN Energy.  

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