Many factors are weighed before a midstream company commits to building, or a shipper commits to shipping on, a major crude oil pipeline. Where is incremental pipeline capacity needed? What would be the logical origin and terminus for the pipeline? What should the project’s capacity be, and what would be the capital cost of building the project? Where the economic rubber really meets the road is the question of what unit cost––or rate per barrel––would the pipeline developer need to charge to recover its costs and earn a reasonable rate of return on its investment. A really important aspect of that is what the developer will be allowed to charge, once regulators get into it. Today we continue our review of crude oil pipeline economics with an overview of who regulates oil pipelines, how they do it, and what it means for rates.
In Part 1 of this series we discussed the fact that new pipeline development is driven by either need or opportunity, and more often than not, a combination of the two. The key question that pipeline developers and their customers (the shippers) have to consider before committing to build new capacity, we said, is whether it will “pay” to flow crude on the pipeline once it’s built––not just the first year or the first three, but for years if not decades to come. To answer this question, pipeline developers and shippers have to consider both current and future economics. There are three fundamental factors that drive pipeline economics: 1) future supply dynamics (and the resulting price impact) at the origination point (Point A); 2) future demand (and price) at the destination point (Point B); and 3) the transportation cost to flow crude from Point A to Point B.