Until November 2014, the oil market was partly controlled by the OPEC Cartel. With Saudi Arabia, the only country with solid spare buffer capacity, acting as swing producer, OPEC was able to support a price around $110/barrel. But the artificially high prices under the cartel regime had some undesirable effects: OPEC lost ground to the upstart U.S. shale players and Russia. In response, Saudi Arabia, expectantly introduced a new oil order November 2014 to defend market share. With a more competition-driven market, the thought was that the new price equilibrium would move closer to the marginal cost of production, driving out the high cost U.S. shale plays. But the Saudis found out that U.S. shale is not static, with the oil price drop U.S. shale producers focused on improving operational efficiencies and extracted pricing concessions out of the service providers, net-net dropping the shale cost curve by $20 per barrel. More recently, with the softness in Chinese growth and the overhang of Iranian oil flooding the market, oil prices have moved to $50 per barrel. It remains to be seen how much additional cost declines and efficiency increases are still achievable in U.S. shale. We have focused the last 10 years as an industry on finding shale plays. With lower prices, our focus has now shifted to streamlining the manufacturing process to lower the cost structure. U.S. shale is here to stay.
Of particular interest, and potential drivers of arbitrage opportunities in M&A are the differences in median valuations of U.S. shale plays. Petroleum reserves can be interpreted as storage options. Hydrocarbons (oil and gas) remain trapped in formation until operators drill wells, pressure-depleting reserves. Wells have drilling and operating costs associated with recovering hydrocarbons, setting a strike price on an oil and gas storage option. We can approximate this strike price as the finding and development (F&D) cost plus the associated lifting cost per barrel of oil or MCF of gas. Furthermore, the total recoverable reserves per well, or EUR (estimated ultimate recovery) dictates the magnitude of F&D costs per barrel or MCF. For example, a well that costs $1 million to drill and recovers 100 thousand barrels of oil yields an F&D cost of $10 per barrel of oil. Compare this to a well that produces only 20 thousand barrels of oil. The latter well, thus, has a F&D cost of $50 per barrel of oil. Add to this an estimated lifting cost (the operating cost associated with producing hydrocarbons which are typically utilities, field labor and transportation) and this may add another $5 per barrel in our example above. In this scenario, we have two wells with two very different option strike or breakeven prices: well number one of $15 per barrel and well number two of $55 per barrel.
On a macro level, oil and gas basins work in this same way. The drilling (F&D) costs, lifting costs and well EURs all contribute to the breakeven price per barrel. Companies with operations in these various basins thus experience varied cash flow and returns from drilling opportunities. As such, investors allocate a premium or discount to public companies depending on the underlying commodity market. For example, in a high-priced environment, companies with high breakeven development costs may trade at a premium because of an abundance of in-the-money development locations. On the other hand, companies with less development inventory but lower breakeven costs may trade at a premium in lower price environments. For these reasons, we expect to see differences with respect to how the market values oil companies based on basin exposure.
Source: Headwaters Industry Research
Against this backdrop, the oil industry is looking at about 50,000 existing wells in the U.S. that may be candidates for a second wave of fracking, using techniques that didn’t exist when they were first drilled. As new horizontal wells can cost as much as $8 million, while re-fracking costs about $2 million, there are significant potential savings. While the number of wells fracked in the U.S. last year climbed 64 percent to 18,200 compared to 2011, the total number of fracking stages more than doubled. That means there are a lot of older wells with primitive frack work that are prime candidates for a fresh workover.