Eight years into the Shale Revolution –– and two years into a crude oil price slump that put the brakes on production growth –– midstream companies continue to develop new pipelines to move crude to market. As always, the aims of these investments in new takeaway capacity may include reducing or eliminating delivery constraints, shrinking the price differentials that hurt producers in takeaway-constrained areas, or giving producers access to new markets or refineries access to new sources of supply. Whatever the economic rationale for developing new pipeline capacity, midstreamers and potential crude oil shippers need to examine–– early on –– the likely capital cost of possible projects, if only to help them determine which projects are worth pursuing, and which aren’t. Today, we begin a series on how midstream companies and potential shippers evaluate (and continually reassess) the rationale for new crude pipeline capacity in today’s topsy-turvy markets.
This blog is a spin-off of sorts from our But I Would Pipe 500 Miles series, in which we walked through the details of the Pipeline Economics Estimation Model for natural gas pipelines that is discussed at RBN’s School of Energy. In the gas pipeline series, we laid out the market dynamics that have led to development of a number of major gas pipeline projects in recent years (with more to come) and the economics that have to work to support the new capacity. We then discussed –– step-by-step –– how pipeline developers determine the sizing of potential projects, estimate project costs and assess whether the likely tariffs for moving gas on the pipeline would justify a project. Finally, we tested our model with a real-life example. Gas pipelines and oil pipelines are very different animals, of course –– hence the need for a separate series on crude oil pipelines.
The Shale Revolution has had a major effect on where crude is produced and (as a result) where pipelines are needed to transport crude to market. In other words, despite all the pipeline infrastructure already in place (see Figure 1), more will be needed to address crude-delivery shortcomings. Consider for a moment the Bakken region in western North Dakota and eastern Montana. For years prior to the widespread use of hydraulic fracturing, 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 was pipeline congestion and significant price discounting while Bakken producers and midstream companies scrambled to develop alternative routes to market. The near-term solution 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). But moving crude by rail is more costly on a per-barrel basis than moving it by pipeline, and new pipelines were, in fact, built to allow Bakken oil to be transported to market more cost-effectively. Most recently, Kinder Morgan’s 485-mile Double H pipeline (light green line in eastern Montana and Wyoming) 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 (purple line from southeastern Wyoming to Oklahoma) to the crude hub at Cushing, OK and various points in between. And now, as we discussed a few days ago in “Tighten Up –– Dakota Access to Close Gap in Bakken Pipeline Takeaway Capacity,” a development team that includes Energy Transfer Partners, Phillips 66, Enbridge Energy Partners and Marathon Oil is building the 1,124-mile, 450-Mb/d Dakota Access Pipeline (DAPL) from the Bakken to the crude hub (and Phillips 66 refinery) in Patoka, IL, apparently killing off the competing Sandpiper Pipeline project in the process.