What does USD 50 WTI mean for Permian producers?

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US tight oil producers’ wishes have come true, with WTI hitting $50 per barrel. And what a comeback it has been – from a historic negative settlement less than a year ago, to a slow but steady climb toward that mark, aided by some strong oil market interventions and macroeconomic influences such as expansionary monetary policies in the US and other countries. Following Saudi Arabia’s announcement to voluntarily cut production on the back of the OPEC+ group’s meet, the NYMEX WTI futures curve for the more immediate months rose to $50, though significant backwardation still remains in months further out, with the tail end trending toward the mid-$40s. As we highlighted earlier today, a WTI price of $50 will provide tight oil producers strong incremental cash from operations in 2021, which can justify substantial capex increases. This raises a range of questions for the most prolific US onshore geology – the Permian Basin: can operators in the region substantially increase production in 2021 when output has already recovered to the pre-Covid-19 peak of 4.9 million barres per day (bpd)? Or will the industry remain disciplined and stay in a production maintenance mode, boosting free cash flow generation to record-high levels? Or will the industry stay committed to the hard ceiling on growth rates it had communicated to investors in the third-quarter earnings season?

The answers to these questions are not easy and we need to remember that Permian activity and production is still driven by nearly a hundred differnt producers with varying ownership type, size and strategy. Even so, we need to realize that the market is witnessing a full price recovery and the incentive to go back into a sustainable growth phase is already here. Not only did WTI touched $50, but local gas and NGL prices in West Texas are higher than they were for most of 2019 and the first half of this year. Dry gas and NGL has accounted for 47-48% of total Permian production, in terms of barrels of oil equivalent, in recent months, up from around 43% in 2019. Together, they contributed a record high 26% to the basin’s total hydrocarbon revenue as of early January, based on spot prices, largely thanks to the Waha marker touching $2.5 per MMBtu for the first time in several years as Kinder Morgan’s Permian Highway pipeline began commercial operations. That marks a big change in the importance of dry gas and NGL production in companies' decision-making process, from the 1Q19-1Q20 period when gas and NGLs were both viewed as sub-products and accounted for only about 12% of the region’s total hydrocarbon revenue. As of early January 2021, the average spot boe price for Permian producers reached $36.7 – more or less the same price realized in 2019, when Permian activity was twice as high, and just 10% below the average pricing from 2018. This provides a clear rationale behind a structural increase in activity in the coming months if the current price environment persists and improving cash flow balances allow for incremental capex.

Yet, we should not forget tight oil’s new business model, and the industry’s focus on disciplined spending, free cash flow generation, deleveraging and cash returns for investors. The reinvestment rate – or the percentage of upstream cash from operations going into capex – for Permian tight oil activity has been declining steadily since 2017 and the Covid-19 downturn accelerated the transformation toward self-financed development. Between 2019 and 2020, the basin’s reinvestment rate fell from 121% to 84%, marking an important milestone with the rate for tight oil sliding below 100% for the first time ever. In fact, as the capex schedule was heavily frontloaded in 2020, the recovery in cash flow from operations in the second half of the year has meant that the reinvestment rate fell to around 70% in the last three months.

Even so, we need to keep in mind that the figure only reflects a general direction of all active companies combined. Even if we look at the top-20 Permian producers, their reinvestment rate for the basin exhibits a high degree of variability. 

With all the variability, operator strategies and reinvestment rate targets, the bottom line is that the current market environment encourages a quick uptick in Permian activity, resulting in a new phase of sustainable production growth in the medium-term.  

The sensitivity of Permian's future production outlook to both the price decks and the reinvestment rate is significant. Even if oil prices remain at $50, there is some risk of another period of depressed gas differentials from 2023, even with new offtake capacity such as the Permian Highway and Whistler infrastructure, as associated gas production is set to grow significantly. Having said that, the potential degradation in local gas prices, toward $1.00 rather than the $2.50 Waha average in 2021-2025, might end up reducing Permian's oil supply by about 900,000 bpd in December 2025 if the reinvestment rate averages at 60%. However, it is more likely that poor gas pricing will result in higher reinvestment rates and reduced profitability rather than a slowdown in oil growth (i.e. higher reinvestment rate) based on the historical evidence from 2018-2019.