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.
Price Differentials
Crude oil production in the Permian’s Midland and Delaware basins continues to rise, and producers in the red-hot shale play are hoping there will be enough pipeline takeaway capacity to handle all that growth. This is serious stuff—the Permian’s success the next few years will depend to a considerable degree on whether producers and the midstream sector can avoid the major constraint-driven price differentials between the Midland, TX hub, and destination markets like the Gulf Coast and Cushing, OK, that already have hit the Permian twice this decade. Today we discuss the prospects for another round of takeaway/price-differential trouble in the Permian as soon as late 2017/early 2018 and again in 2020-21.
Although California refineries initially met the criteria that spurred development of crude-by-rail (CBR) shipments to other coastal regions (lack of pipeline infrastructure and wide crude price differentials between stranded inland supplies and coastal alternatives) neither rail shipments or terminal build outs have made much of a dent in the Golden States’ crude supply. At their height in December 2013 CBR shipments into California reached 36 Mb/d – just 2% of the State’s 1.9 MMb/d refining capacity and they have since dwindled to a trickle. Today we examine the low pace of shipments.
With crude prices below $30/Bbl and the price spread between U.S. domestic crude benchmark West Texas Intermediate (WTI) and international equivalent Brent trading in a very narrow range – the economics of moving Crude-by-Rail (CBR) rarely make sense any more. Rail shipments are down across all regions and railroads are reporting sharply lower revenues from CBR shipments. Today we start a new series revisiting the regions where CBR traffic boomed a couple of years back and contemplating its future value to shippers and refiners.
US domestic crude oil production took off in the past year. Most of the production growth is coming from three shale oil plays – the Bakken, Eagle Ford and Permian basins. A number of factors have combined to allow rising production to continue. Today we review what sustains increased crude production and whether it can continue.
The chart below shows total US domestic crude production since the start of 2009. Around August 2011, the level of production started to ramp up dramatically. Despite a brief respite when crude prices fell below $80 / Bbl earlier this year, production is rising again. The latest data from the Energy Information Administration (EIA) shows that between September 2011 and July 2012, production increased from 5.6 MMb/d to 6.3 MMb/d - that’s a 62 Mb/d production increase every month.