For the past five years, crude oil producers in the Bakken have depended on railroads to transport a significant share of their output to market—there simply hasn’t been enough pipeline capacity out of the tight-oil play. Now, construction of the long-awaited, 450 Mb/d Dakota Access Pipeline (DAPL) is finally poised to begin, and a late-2016 online date for DAPL is planned. DAPL’s capacity would enable producers to further reduce their use of crude-by-rail, but with Bakken production on the decline, will DAPL really be needed? And what about additional out-of-the-Bakken takeaway capacity being planned? Today, we consider the challenges and pitfalls of developing midstream infrastructure in fast-changing markets, focusing on Bakken crude.
How midstream companies prepare for (and respond to) changing production patterns for crude oil, natural gas and natural gas liquids (NGLs) has been one of the frequent—and most widely followed—topics among the hundreds of RBN blogs written and posted over the past few years. It’s not surprising. After all, as producers know all too well, hydrocarbons produced at remote locations have little-to-no value unless they can be efficiently and cost-effectively transported to market. (It’s very rare for oil or gas to be consumed very near where it’s produced.) The Bakken region in western North Dakota and eastern Montana provides a classic example. For years prior to the Shale Revolution, long-existing pipeline capacity out of the Bakken could handle the modest volumes of conventional oil being produced there. By 2011, though, Bakken tight-oil production had begun a steep, rapid rise, quickly outstripping available pipeline capacity (much of which had to be shared with crude heading south/southeast from western Canada). The result? Pipeline congestion and significant price discounting while Bakken producers and midstream companies scrambled to develop alternative routes to market. The solution (and they sure needed one!) was the development of rail loading terminals—they could be built quickly and at relatively modest costs, and they could use existing infrastructure (the nation’s railroads). Crude-by-rail (CBR) also allows for destination flexibility; in other words, if a producer could achieve higher netbacks (the crude sale price minus transportation costs from the wellhead) from railing its crude to the East Coast or the West Coast (neither of which is connected to crude producing regions via pipeline) instead of the Midwest or the Gulf Coast then, heck, rail it to East or West Coast. In all, 21 rail terminals have been built in the Bakken; their combined capacity is a fairly astonishing 1.5 MMb/d (compared to current Bakken production of just over 1 MMb/d—down from its December 2014 peak of 1.3 MMb/d).
While moving crude by rail is considerably more costly on a per-barrel basis than moving it by pipeline, CBR out of the Bakken made perfect sense for two primary reasons. First, as we described in our recent Drill Down Report on CBR, West Texas Intermediate (WTI; the U.S. domestic Midcontinent benchmark) was selling at a steep discount to Brent (the international benchmark). That discount, which peaked at nearly $30/bbl in 2011 and averaged $18/bbl in 2012, enabled Bakken producers to achieve solid netbacks even after factoring in CBR costs. And second, there simply wasn’t enough pipeline capacity out of the Bakken to meet their takeaway needs anyway—CBR was (and still is) needed.
But economic conditions changed. The differential dropped from over $20/bbl in early 2013 to average less than $3.00/bbl in July 2013. The discount bounced around a lot through the rest of 2013, 2014 and most of 2015, but in 2016, WTI and Brent have averaged within $1.60/bbl of each other, with WTI selling for more than Brent for a few days. Over the years, incremental pipeline capacity out of the Bakken has been added.. Most recently, Kinder Morgan’s 485-mile Double H pipeline opened for business in February 2015; it can move up to 84 Mb/d from the Bakken production area near Dore, ND to Guernsey, WY, where Double H interconnects with Tallgrass Energy Partners’ 320-Mb/d Pony Express Pipeline to the crude hub at Cushing, OK and various points in between. We’ll get into the capabilities and flows of Pony Express in Part 2 of this blog series.