RBN Energy

Houston area refineries are the first to experience the full impact of the flood of domestic and Canadian production headed to the Gulf Coast in 2013 and 2014. These refineries have traditionally relied on floating storage in the form of import cargoes in transit to buffer them against supply shocks. Now the region is adapting to new crude supplies mostly delivered by pipeline. As imports decline, the floating storage option disappears, leaving the potential for congestion caused by inadequate onshore working storage. Today we calculate the storage impact of these changes.

Refineries in the Rocky Mountains region, defined by the Energy Information Administration (EIA) EIA as Petroleum Administration for Defense District (PADD) IV, are smaller and less complex than they are in the rest of the U.S. The region is landlocked and the 16 refineries – average size only 42 Mb/d - rely on U.S. light sweet crude produced locally or in North Dakota as well as Western Canadian heavy crude. The combination of rich supplies of crude and increased demand for refined products such as diesel means that refinery margins are high. These healthy economics are encouraging refinery expansions. Today we examine these plans.

During the days when Gulf Coast refineries were dependent on crude imports for the majority of their feedstocks, tankers delivered crude from overseas markets. Those same tankers also played an important role in preventing refinery supply disruptions because they acted as a floating storage component in the supply chain. With waterborne imports to the Gulf Coast declining as domestic and Canadian production is increasingly delivered by pipeline, the buffer provided by floating storage will be much reduced. Today we continue our series looking at Gulf Coast crude storage needs in the shale era.

If as appears likely, US regulators impose new rail tank car safety standards by the end of 2014 including the phasing out of older designs, the cost for a new car could be as much as $150,000. Retrofitting older designs to meet new standards could range between $20,000 and $60,000 per car. The resulting higher lease costs, concerns about safety and lingering logistics issues from this past winter are leading to producers looking more favorably at pipeline projects. The latest data this week from North Dakota indicates crude-by-rail traffic out of that State fell by 11.5 % from 693 Mb/d in November 2013 to 614 Mb/d in May 2014. Today we look at the impact of these changes on future crude-by-rail traffic.

Just over a week ago (July 3^rd) Reuters reported that Enterprise Product Partners (EPD) sold their first 400 MBbl export cargo of condensate to Japanese trader Mitsui. That export follows private letters from the Bureau of Industry and Security (BIS) to Enterprise and Pioneer that represent a change in the government’s interpretation of 40-year-old legislation banning the export of unprocessed crude and condensate from the US. The apparent relaxation of the rules could open up export opportunities for shale producers – especially in the wet gas / condensate window of the Eagle Ford in South Texas. Today in the first of a two part series we describe existing stabilizer capacity and export routes to market in the Eagle Ford.