Why has light tight oil production proven so resilient in the Permian?

September 2016 | Evelina Pagkalou, Autumn Hong Morse, and Ryan Whitmire


Oil production from the Permian basin has barely declined since oil prices collapsed, while the rest of onshore US LTO production has declined by more than 500 Kbd in the past 12 months. The resilience in Permian production, especially from horizontal wells, has been supported by two factors. Firstly, more new oil is produced from each well due to acreage high-grading and improved well completion design. We have seen an initial production (IP) improvement of 15-30% per horizontal well since 2014. Secondly, potential upside, linked to its high resource and productivity increase, as well as the access to capital of its core operators, enabled to keep activity high in the Permian Basin even in a low oil price environment.

In the last four years, the US oil industry has staged a global oil revolution driven by light tight oil (LTO). After years of declining production and rising imports, the exploitation of oil trapped in tight oil formations through horizontal drilling and hydraulic fracturing turned the US to the largest liquids producer in the world. In 2015, US total liquids production exceeded 15 million b/d , with over 25% coming from LTO. Yet, after the collapse in oil prices, LTO basins have suffered from an impressive 80% reduction in drilling activity. As a result, in the last 12 months US LTO production has declined by more than 500 Kb/d, a decline made even more prominent when contrasted with the 700 Kb/d growth in the same period from the previous year. If we extrapolate the growth rates before the oil price collapse, the price decline has already knocked more than 1,200-1,500 Kb/d of potential LTO production out of the market in 2016, which would have alone covered all the global liquids demand growth in that year.

Nonetheless, the one basin that seems to be resilient despite the industry’s struggle is the Permian basin. The Permian basin is a large sedimentary basin made up of a complex series of oil-soaked sandstones, carbonates, and shales, and covers much of the western region of Texas and the southeastern region of New Mexico. It is further divided into a number of sub-basins, with 84% of the oil production coming from the more prominent Midland and Delaware sub-basins. Conventional oil has been produced from Permian for a long period of time, with the first well being drilled in 1920, but LTO production is a fairly recent development. Even though it holds the largest LTO resource in the US, the basin’s development lagged behind North Dakota’s Bakken and Texas’ Eagle Ford due to the complex geology of the Permian shales. Yet throughout the period of June 2015 to June 2016, the Permian was the only source of growth in LTO, expanding production by 6% while the rest of LTO declined by 16%. In fact, half of today’s rig fleet is drilling in the Permian basin: in July 2016 there were 145 rigs drilling horizontally for oil in the Permian basin vs 151 for the rest of the country’s LTO basins, with 60% of rig additions targeting the Permian.

We have identified two main drivers behind this resilience of activity: attractive economics through the recent operational improvements, and a strategic investment mentality from the US operators, who are betting on the Permian basin holding the future for US LTO.



Exhibit 1: Half of the active oil horizontal rigs are currently drilling in the Permian basin

SOURCE: Baker Hughes


Increased oil production per well due to high-grading and well efficiency gains

When comparing historical data, it is clear that initial production rates (IPs) in the Permian Basin have increased significantly since the price downturn. Both the Midland and Delaware Basins, the two main sub-basins of the Permian, saw significant gains in well productivity from 2014 to 2015 in their core. The source of the growth in productivity was a combination of high-grading, which involves drilling only proven high-productivity acreage, and drilling & completion design improvements. These design improvements included the use of longer laterals and changes in the completion designs of the wells, namely in type and volume of proppant and in frac fluid type.

IPs in the core acreage of the Midland basin increased overall by an impressive 33% from 2014 to 2015. High-grading accounted for ~40% of this growth, while majority of improvement (60%) came from the design changes including longer lateral drilling and frac design changes. Operators used more proppant, almost all of it sand, and moved towards slickwater completions instead of using the more expensive crosslink-slickwater hybrid frac fluids.



Exhibit 2: Longer laterals, more sand, increasing slickwater fracs, and more frac water characterize well design trend in Permian

SOURCE: NavPort data, Energy Insights analysis


The Delaware Basin is a slightly different story. This western region of the Permian was already at a further stage of development than the Midland; therefore, productivity gains were smaller. IPs increased by a total of 14% from 2014 to 2015. High-grading contributed 13% of IP improvement while, again, most of improvement (87%) was driven by design changes, especially from longer lateral length drilling. Operators used more proppant in Delaware similarly to the Midland basin, but they brought the proppant cost down by substituting portion of resin-coated with sand. They also moved to a cheaper frac fluid, abandoning crosslink and hybrid completions in favor of slickwater.

Regardless of differences between the Midland and Delaware Basins, the increase in initial production rates outpaced the increase in costs from using longer laterals. As a result, the average breakeven price for a well in both Midland core and Delaware core came down by 39% to $45/bbl and $43/bbl respectively, making the Permian plays far more attractive to drillers.



Exhibit 3: The Permian Basin has seen significant IP growth due to acreage high-grading, longer lateral lengths, and improved fracture designs

SOURCE: NavPort data, Energy Insights analysis


The Permian as the industry’s new favorite growth engine

Although the Permian breakevens did come down significantly, drilling in the Permian on average still has a lower return on the wellhead than drilling in the core areas of Bakken or Eagle Ford, where breakevens touch $40/bbl. Yet, drilling activity in both these regions collapsed, while the Permian sustained the attention of the industry. This trend showcases the reality of the maturing US LTO industry today under low prices, where drilling activity is based not just on well economics, but also on future expectations, strategic, and financial considerations. We believe that the drilling attractiveness of the play has been enhanced by its potential upside, linked to its high resource and potential productivity increase, as well as by the access to capital of its core operators.

  • Potential Upside: Investing in drilling activity and infrastructure in the Permian carries a higher future upside, due to the multiple resource benches that exist on top of each other and increasing well productivity. As an example, in the Delaware Basin, both the Wolfcamp and Bone Spring benches have proven their commerciality already; the 1st and 3rd Bone Spring sub-benches are also in the process of delineation and the Pennsylvanian reservoirs have further resource potential to be explored. The number of available productive benches and their thickness mean that for any well drilled in the Permian acreage, there is the potential of additional drilling activity later down the line. Furthermore, the basin has seen jumps in well productivity as discussed above that offer an attractive value proposition of improved well economics in the future and incentivize further drilling activity. As a result, having a position in the resource-rich Permian basin is considered a favorable addition to a producer’s corporate strategy, as was proved in the last wave of asset and equity M&A in the Permian since 2015. A new or improved position in the Permian allows larger cap companies to showcase continuous reserve and production growth, and achieve better reserve replacement rates.
  • Availability of capital: Operators active in the Permian entered the activity downturn with higher liquidity and also currently enjoy better access to capital, allowing them to maintain drilling. The largest Permian LTO operators in late 2014 had more profitable hedges, higher cash reserves and unused credit lines, and lower leverage than operators in the Bakken and Eagle Ford. As a result, there was less of a need to reduce drilling capex to rebalance their operating cash flows. Since then, Permian operators have had the best access to financial markets in part due to the potential upside mentioned above, and in part due to the health of their balance sheets; average net debt to EBITDA of Permian players is 50% lower than Bakken and Eagle Ford operators. Equity markets are still open for Permian players - Pioneer has already executed 3 equity raises, the last of which was in mid-June, 2016. Similarly, they also have the lowest utilization of their credit lines. All this high liquidity has, in turn, allowed them to keep rigs on the ground and support operations despite the low oil prices.


Exhibit 4: Permian operators have better access to financial markets, enabling continued drilling activity

SOURCE: Capital IQ, CPAT


In summary, the Permian basin has been extraordinarily resilient in the face of crashing oil prices due to three main factors: continuous improvements in drilling & completion design and high economic and resource upside, matched with operators that have healthier balance sheets. The combination of financial health of operators and high resource upside has placed the Permian Basin in a unique position to be the leading growth engine for the US LTO industry not only right now, but moving into the future.

GET UPDATES

Stay informed by subscribing to our insights—delivered directly to your inbox.

SUBSCRIBE
About the authors

Evelina Pagkalou is a senior analyst with Energy Insights in McKinsey's London office.
Autumn Hong Morse is a solution manager and Ryan Whitmire is a summer analyst, both with Energy Insights in McKinsey's Houston office.