Low acreage prices drive US onshore consolidation as industry matures

November 2020

Low acreage prices drive US onshore consolidation as industry matures


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The US onshore shale industry is set to consolidate further through 2021 and 2022 as producers facing a challenging cash flow environment see a buyout as the best option to exit, particularly in the current market environment where reduced corporate acquisition premiums have seemingly become a new norm. A sharp fall in acreage prices will also aid the drive, and investor interest for a combined entity could potentially revive as efficiencies improve amid a continued reduction in costs. In part driven by that philosophy, mergers and acquisitions (M&A) in the onshore industry reached a record high in the second half of this year, recovering sharply from the dramatic slowdown in the second quarter as the rapid spread of Covid-19 created a period of massive uncertainty, pushing both potential buyers and sellers to the sidelines.

So far this year, we have seen both mergers of equals as well as large acquisitions by major producers. That’s in contrast to 2019 when most of the transactions were small premium deals between play-focused operators. By acquiring a neighboring player, operators were typically able to increase their existing acreage position, realizing operational synergies and growing output at a reduced cost. The recovery in M&A in the second half of this year is helping extend the trend of consolidation that began in 2018, which was briefly disrupted earlier this year.

Figure 1 displays onshore deal values in the US per month as well as indexed oil and gas prices. Overall, we expect this trend to continue across the shale industry over the next two years as a large number of producers with challenging cash flow balance view consolidation as the best exit opportunity.


The largest financial push for consolidation comes from a significant acreage price reduction, as WTI plunged, while the overall equity investor sentiment for pure upstream producers had anyways dropped even before the latest market downturn. Figure 2 shows a decline of more than 70% in average acreage prices across the US, from $17,000 per acre in 2018 to $5,000 per acre in 2020. Fundamentally, tight oil and gas economics have improved significantly since 2018, yet the implied price strip in our new base case is substantially lower than it was in 2018, which cuts off a large portion of the industry’s undeveloped NPV potential. The Permian Delaware, at $30,000 per acre, and the Midland, at $17,000 per acre, are still leading in terms of acreage prices. Naturally, the multi-stacked potential of the play allows for simultaneous development of several zones from the same spacing unit, which in turn multiplies the surface acreage's NPV potential.

When it comes to the fundamental upstream asset value of specific leading public operators, we see a per acre drop of close to $20,000 from the 2018 levels, which represents a 44% reduction in the two years, from $45,000 per acre to $25,000 per acre in 2020. 

The Permian Basin has seen a more significant reduction in valuations than other basins, based on historical deal price comparisions. The most recent Permian-focused transactions were at little to no acquisition premiums, with an average price of about $24,000 per acre. This corresponds to a staggering 67% decline from the earlier deals in 2018.

A recent analysis confirms that the reduction in valuations is promoting consolidation that wouldn’t have happened in 2018-2019. Low equity prices and the need for investor support is motivating many operators to look for new options to merge, especially if it doesn’t involve heavy debt and cash. In turn, asset spin-offs and the sale of non-core acreage in liquids basins are comparatively lower now and we do not foresee demand for such assets rising in the coming quarters till the time WTI recovers above the $45 per barrel mark as most operators tightly hold on to their Tier 1 inventory.

The actual impact of these recent transactions on future US crude supply will depend on when most operators see the full result of synergies from the mergers and standardization of operations across the new portfolio and assets, which takes at least one to two years, according to our base case and the historical evidence of post-2018 deals. Drilling and completion costs, on a per foot basis, have declined by 15-20% this year across most basins, driven by a combination of increased focus on Tier 1 acreage, a collapse in spot prices for oilfield services and a continuous penetration of longer laterals. Further consolidation and an increased degree of standardization, along with continued reductions in service costs, would likely result in an additional fall of up to 5% in industry-wide average D&C costs next year. Moreover, even more capital is likely to be allocated to Tier 1 acreage in the Permian in future, ultimately pushing the P50 breakeven price in the basin down toward $20 per barrel (PV10 wellhead breakeven prices).

The ongoing onshore consolidation will surely result in a deceleration in the country's rate of production growth in future. The industry is moving away from the historical reinvestment rate of 75-90% toward a more conservative target of 70-80% because of a lack of investor support for aggressive growth models. This will take the growth rate of future oil production, over 2021-2025, from 7-8% per year under the old model, to 3-5% per year in a $40 per barrel WTI environment. We, however, argue that the gradual recovery in US tight oil production in a $40 environment should be viewed as the base case. The industry will be able to achieve it while delivering on its deleveraging target and generating material FCF yields from 2021. Under the new industry model, we expect US tight oil production to recover to the pre-Covid records by 2023, with nearly all growth coming from the Permian Basin. The Permian is the only major region which, in our view, will be able to surpass its pre-Covid production record and hit 6 million bpd by 2025.

The impact of the recent mergers on the global crude supply, demand balance might have a dual influence – it might stimulate additional capital support, which in turn could lead to a steady rise in US volumes if WTI returns to $50 per barrel. On the positive side, the smaller the peer group of large producers driving the increases in crude volumes, the easier it will be to ‘control’ and forecast US supply.