There’s a fierce battle on to build new intra-basin pipelines in the Permian to transport crude oil from gathering systems in hot new production areas to takeaway pipelines out of the play — and to give producers and shippers destination optionality in the process. Participants better bring their A game, though, because successfully developing “shuttle” pipelines in the Permian requires a keen understanding of what’s happening on the field and how best to move the ball forward. Three key factors are lining up producer commitments, providing that critical takeaway optionality, and minimizing the total cost of moving crude from the lease to the Gulf Coast, Cushing or other destinations. Today, we begin a blog series on existing and planned intra-basin oil pipelines in the Permian — what drives the development of these in-demand pipeline “legs” and what it takes for them to succeed.
We’ll start with a brief recap of how we got to where we are today. Building new pipeline capacity isn’t just about providing the physical means to transport barrels of crude from Point A to Point B. It’s also about helping producers get the highest possible price per barrel. Back in the olden days (say, before 2010), most of the oil produced in the Permian flowed north (on either the Plains Basin Pipeline or Occidental Petroleum’s Centurion Pipeline) to the crude storage and distribution hub in Cushing, OK. (Only Energy Transfer Partners’ West Texas Gulf Pipeline ran to the Gulf Coast, and that pipe’s capacity was much smaller then than it is now.) At their origination ends in the Permian, the Basin and Centurion systems each have a number of tentacles that connect directly with Permian gathering systems or truck terminals — everything was pretty simple back then. But the Shale Revolution changed everything. Before you knew it (by 2011-12), surging crude production in the Bakken and western Canada exceeded Midwest refinery demand and because there was very little pipeline capacity from the Mid-Continent to the Gulf Coast (where half of all U.S. refining capacity resides) supplies started backing up in Cushing. The Cushing supply glut — exacerbated by rising shale production in the Permian itself — resulted in heavy discounting for Cushing benchmark West Texas Intermediate (WTI) versus Louisiana Light Sweet (LLS) at the Gulf Coast. How heavy? In 2011, WTI at Midland, TX (the heart of the Permian) was selling for $18 less per barrel (on average) than LLS at the Gulf, and in 2012 that differential increased to a staggering $22 per barrel.
That’s where takeaway pipelines to the Gulf Coast come in. To avoid the crude logjam at Cushing, midstream companies developed new Permian-to-the-Gulf pipeline capacity, including the reversal of Energy Transfer Partners’ small Amdel Pipeline in 2012 and Magellan Midstream Partners’ larger Longhorn Pipeline in 2013, followed by the construction of Magellan and Plains All American’s BridgeTex Pipeline (2014), Plains’ Cactus Pipeline and Energy Transfer’s and ExxonMobil’s Permian Express II (2015 for both), and Plains’ and ExxonMobil’s PELA Pipeline (2016). (See RBN’s Drill Down Report on Permian crude oil pipelines for more on these pipes.)
But takeaway pipelines are only part of the story — they take crude out of the Permian to various faraway destinations (mostly to the Gulf Coast), but they only provide destination optionality to a specific producer or shipper if it can connect to an intra-basin pipeline network capable of moving its crude from the wellhead to two or more takeaway pipes. In other words, no connection to a shuttle with multiple interconnects with takeaway pipelines, then no destination optionality. And without optionality, producers and shippers are locked into a single end-market and are at risk of becoming price-discounting victims the next time their lone market suffers a differential blow-out.
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