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Permian Oil Pipeline Constraints – It’s complicated

Permian crude differentials have become highly volatile, exceeding Permian oil pipeline tariff costs to the Gulf bringing crude by rail back into the market. However, based on historical utilization and differentials, and an estimated cost of rail around $6 – $8/bbl, May average month-to-date differentials of $11.71/bbl suggest that access to rail as a relief valve is also likely constrained.  This brings us to the focus of this blog: Permian oil infrastructure is complicated and requires thinking through several transportation components by sub region. Furthermore, oil flow data is limited or significantly lagged, making timely analysis challenging.  However, there are key ways to measure and think about infrastructure to help understand why differentials are significantly wider than would be expected if Permian barrels were able to freely access pipeline and rail loading facilities.

The most common way to think about Permian differentials is to calculate Permian pipeline capacity compared to production.  This seems straightforward on the surface, but, the process gets complicated quickly and requires a more nuanced approach.  The map below shows the Permian Basin broken out by the Delaware and Midland sub basins as well as pipeline infrastructure supporting the region.  The red line indicates where many analysts typically measure pipeline capacity for the Permian to understand differentials.

However, as you move back towards Midland, TX, it is not surprising to discover that the pipeline capacity, as represented by the orange arc, is different and would therefore result in a different utilization and differential outlook than one calculated based on the red arc.  Similarly, as you move towards the Delaware Basin, the capacity for the yellow arc varies from both the orange and red constraint lines.  To fully understand Permian oil constraints, it is important to consider potential constraints moving from west to east across the basin and what modes of transportation like rail or truck are available.

The chart below highlights this fact. The utilization calculation is based on a measurement corresponding with the red arc in the chart above and the prices shown represent the spread between WTI-Cushing and WTI Midland (WTI Cushing price minus WTI-Midland price).  Using the utilization measurement across the red arc, BTU Analytics estimates that May 2018 Permian pipeline capacity utilization was at 90% of capacity, which has historically corresponded with a much tighter spread than $12/bbl between Cushing and Midland.  The wider spread highlights the intra-basin dynamics at play and that producers are likely relying on higher-cost rail and even trucking to move crude beyond in-basin constraints to the nearest injection station via truck and rail to downstream markets.

In fact, a WTI-Cushing to WTI-Midland spread of ~$12/bbl and WTI-Midland to WTI-Houston spread of almost $15/bbl suggests that the marginal crude barrel from the Permian may be moving as far as the Eagle Ford or Borger Texas markets to reach available pipeline and refining capacity via truck. If this is the case, and pipeline and rail access within the basin continues to remain constrained, then the differential outlook for the Permian degrades quickly until new oil projects are completed. While a significant volume of crude in the basin still moves via truck, truck hauls are generally less than 100 miles round trip. As producers look to move past in-basin constraint points, round trip distances could exceed 600 miles, significantly reducing the effective capacity of the existing truck fleet to haul crude from the wellhead. Due to the rapid growth in production and the timing of new pipeline projects, a trucking shortage could emerge driving differentials to new highs as producers discount their barrels to ensure their volumes move to end markets.

To learn more about Midland differential forecasts and a list of Permian pipeline projects expected to alleviate this constraint, request a sample of BTU Analytics’ Oil Market Outlook report.

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Erika Coombs is Senior Manager of Energy Markets at BTU Analytics. She leads the team to deliver energy-market analysis and provides BTU Analytics’ customers with critical information for a variety of energy markets including oil, gas, and NGLs from wellhead to downstream markets. She also oversees BTU Analytics’ oil and gas product suite which includes research on upstream, midstream, breakeven economics, and commodity pricing dynamics. She holds an M.S. in Mineral and Energy Economics from the Colorado School of Mines.

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