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Energy Insights Outlook Overview

North American Shale Oil Outlook to 2025

“Recent development in the Permian, driven by favorable economic conditions, is leading the new growth in the North American shale oil market.”

The rise of North American shale represented an enormous success, but the oversupply it created also helped contribute to the downturn. What changes have been made to shale oil operations so far as a result of that low-oil-price environment, what developments can we expect to see going forward, and what role will each basin play in future production? Our North American Shale Oil Outlook to 2025—developed using our North American Supply Model and other proprietary data collected by Energy Insights—explores the answers to these questions in greater detail.

Five key findings

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Executive Summary

Permian poised to drive the shale oil market for the next 10 years

From Q2 2014 to Q1 2016, oil oversupply—in part caused by rising shale oil production—led oil prices to fall 50 percent and the number of active rigs to fall 80 percent. Though the market remains constrained by capital and rig or labor availability, we’ve seen oil prices recover, drilling activity more than double, and key operational improvements enable the shale oil industry to endure through the low-oil-price environment and beyond.

Recent development in the Permian, driven by favorable economic conditions, is leading new growth in the North American shale oil market. The Permian’s initial production (IP) growth rate for the past 5 years was 20 percent—compared to 2 percent in the Eagle Ford and Bakken—and its early development stage means there are more remaining drilling locations to explore. The basin also benefits from an average core breakeven price for 2017 that is less than $41 per barrel, enabling it to stay profitable despite well-cost increases of 30 percent.

As far as operational improvements are concerned, better drilling efficiency, completion design, and high grading have sustained and will continue to drive growth despite the foreseeable cost escalation of 15–25 percent in the next 2 years. Operators have reduced drilling days by 5 days while improving IP by 33 percent from 2014 to 2016. Improved completion design—like those that use higher volumes of proppant—has increased IP by 35 percent, and high grading in each subbasin has enabled operators to continue to drill and produce even considering the current oil price.

Going forward, under our base case that sees WTI at $60–70 per barrel from 2019 onward, we expect drilling and completions (D&C) activity to grow 20 percent per year and production to grow 12 percent per year through 2021. That increased D&C activity will require total capex spend to grow to near 2014 spend levels, and production will have nearly doubled since 2014, reaching around nine million barrels per day by 2025.

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