The energy industry’s upstream products — crude oil, natural gas and NGLs — are commodities, so the lowest-cost producers generally do best, especially if they are well-connected to downstream markets. Due in large part to the intensity of competition, finite drilling locations, the constant need for capital investment and the chilling effect of political headwinds, the industry is in the middle of a consolidation cycle that has enabled a select group of top-tier E&Ps to build scale — and longer-lasting inventories — in the most productive parts of the most lucrative shale plays. That scale, in turn, helps these Shale Era winners reduce their costs, gain market share and — important in 2023 and beyond — return a big slice of their free cash flow to investors as dividends and stock buybacks. In today’s RBN blog, we discuss what’s driving that “urge to merge” and what it means for industry players large and small.
Mergers and acquisitions (M&A) cycles often play out like a high-school dance. It starts with the Prom King and Queen, and then the most desirable dance partners are eventually taken. Ultimately, the last people to dance are the ones who were too slow to ask and now must react and accept those still left, or end up on the outside looking in.
M&A cycles following that pattern are nothing new in the energy industry. The “Era of the Super-Major” in the early 2000s was kicked off by the merger of Exxon with Mobil in 1999. This consolidation focused on improving the return on invested capital (ROIC) of the combined business. After the ExxonMobil merger, a bevy of acquisitions followed: BP/Amoco/Arco, Total/Fina/Elf, Chevron/Texaco, and the unification of Royal Dutch and Shell. The goal was the same: scale matters and energy companies must deliver a higher ROIC to attract investment dollars. Since the best combinations usually occur early in the consolidation cycle, the number of potential partners shrinks as time goes on, with targets picked more on availability and less on attractiveness.
Those companies dominated the field of U.S. producers as domestic supplies declined prior to the Shale Revolution. So much has changed in the past 15 years that it may be tough to recall how different the U.S. production landscape was prior to that. Most domestic production came from the Gulf of Mexico, plus Alaska’s North Slope, Texas and California. However, as horizontal drilling and hydraulic fracturing took center stage, new areas opened up and the number of rigs per state — and the number of states with active drilling — multiplied.
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