Daily Energy Blog

Over the past couple of years, Corpus Christi has emerged as an attractive refining and distribution hub for Eagle Ford and more recently Permian Basin crude oil and lease condensate. Despite Corpus’s promise, however, currently low commodity prices have made key players skittish about making long-term—and potentially costly—commitments to additional Permian-to-Corpus pipeline capacity, and to crude refining, condensate splitting and marine dock infrastructure investments in or near Corpus. Today, we begin a deep-dive into Corpus Christi-area crude- and condensate-related infrastructure and Corpus’s potential as an even bigger destination for Eagle Ford and Permian output.

While crude oil takeaway capacity out of the Permian Basin from major hubs is probably overbuilt for the time being that is not the case for gathering systems bringing barrels from the wellhead to mainline terminals. Production in the Permian has slowed since the drop in oil prices reduced drilling activity but is still increasing from sweet spots in the Midland and Delaware basins in West Texas where pipeline gathering can save producers as much as $2/Bbl in trucking fees. Today we continue our review of gathering infrastructure build out to deliver more crude to takeaway hubs in the Permian.

Prior to 2012 the only U.S. produced crude delivered by pipeline to Houston area refineries came from offshore Gulf of Mexico or onshore Louisiana fields. The majority of supplies were imports delivered by waterborne tanker. But in just three short years between 2012 and 2015, roughly 2 MMb/d of crude pipeline capacity was built or repurposed to deliver surging light shale crude production and heavy crude from Canada into the Houston area. Refiners have adapted quickly to take advantage of new sources of supply. But with much of the newly minted infrastructure underutilized, midstream companies still need to improve pipeline connectivity and storage accessibility to overcome area logistical challenges. Today we review RBN’s latest Drill Down report on Houston crude infrastructure – released today -- and announce RBN’s new infrastructure database and mapping system, called MIDI.

The cost to charter U.S. Flag Jones Act tankers that are used to transport crude and refined products along U.S. coastal waters is still as high as $75,000/day for medium-range 330 MBbl vessels. That’s four times what it costs for an equivalent foreign flag tanker. Higher charter rates – caused by tight vessel supply in a regulated market – have attracted investment from Kinder Morgan and other midstream companies and the tanker fleet will expand by 40% in the next 3 years. Today we discuss the market potential.

The Jones Act (see The Sea and Mr. Jones) is a federal statute requiring that all goods transported by water between U.S. ports be carried in U.S. Flag ships, constructed in the United States, owned by U.S. citizens, and crewed by U.S. citizens and/or U.S. permanent residents. Because of the regulations, operating expenses are higher for Jones Act vessels (as much as 2.7 times non-flag alternatives according to a U.S. Maritime Administration (MORAD) study in 2011). We have provided considerable coverage of the role that Jones Act vessels have played in the U.S. crude oil distribution system over the past 4 years since shale production increased domestic output including our Rock The Boat series in the spring of 2014. Subscribers to RBN’s Backstage Pass service can download a copy of the comprehensive “Rock The Boat” Drill Down Report that accompanied that series and contained a detailed inventory of the larger vessels and their owners.

After a year’s delay due to permit issues, Enbridge now expects the expanded and reversed 300 Mb/d Line 9B pipeline to Montreal will come online next month (November 2015). The pipeline is an important cog in Enbridge’s Eastern Access and Light Oil Market Access expansion projects and will supply mostly light crude to two refineries in Quebec. As we explain today, the payload will travel a winding route to get to Montreal.

Crude production in the Niobrara shale formation is focused on two areas, the Denver-Julesburg (DJ) Basin in Northeast Colorado and the Powder River Basin (PRB) in Wyoming. Production has expanded in both basins (current output is about 435 Mb/d according to the Energy Information Administration) but much of the recent volume growth has come from the DJ basin. Expectations as recently as last year that production would expand to over 700 Mb/d in the next 4 years have been tempered by the crude price crash. A couple of large pipeline projects prompted last year by those production expectations have been cancelled since but others are still being built. Today we assess crude takeaway infrastructure in the DJ basin.