Speaking on an earnings call a month after petitioning the Texas Railroad Commission to impose supply cuts, Matt Gallagher, CEO of Parsley Energy Inc., summed up the situation facing frackers:
Currently, the world does not need more of our product, and we only get one chance to produce this precious resource for our stakeholders.
The commission didn’t organize shut-ins of wells. So Parsley, taking its cue from prices instead, is just shutting in some of its own anyway. It has also suspended drilling and completing new wells.
The economics of each well — and the companies that own them — differ enormously. But grab an envelope and imagine a well tapping one million barrels of oil equivalent, 75% of it crude oil, the rest natural gas. Benchmark prices: $30 oil and $2.50 gas, translating to, say, $27 and $2 at the wellhead. That implies total revenue from those resources of $23.3 million. Royalties and severance taxes take about $7 million of that; operating expenses and overhead take another $7 million(1). That leaves $9.3 million versus the $9 million spent drilling and completing the well upfront. Factor in time value of money, and that well is seriously underwater.
Besides the back-of-crumpled-envelope quality of that calculation, there are other reasons a producer might keep drilling anyway. Rigs are often contracted for months at a time; for example, Helmerich & Payne Inc., a leading provider, reported roughly a third of its U.S. onshore rig fleet operated under fixed-term contracts at the end of March. Contracted pipeline space, too, must be paid for whether or not barrels flow through it. Taking a company’s activity down to zero is also traumatic for workers and, like a shut-in well, makes it harder to eventually crank back up. Hedges, meanwhile, shield against low spot prices and represent oil and gas contracted for delivery.
Then again, hedges could be settled for cash; it’s not like anyone is screaming for more of the actual stuff these days. Rig and pipeline contracts can also be renegotiated (an order from the Texas Railroad Commission could have helped on that front, but still). And the difficulty of going into hibernation must be set against the implacable demands of low oil prices.
On that note, another rationale for continuing to drill is an expectation of oil and gas prices recovering reasonably soon. Parsley and some other shale operators, such as Diamondback Energy Inc. (which is reducing but not suspending drilling), have indicated they could increase activity again if oil gets back above $30 a barrel (it was trading around $25 Monday morning). Because shale output is very front-loaded, movements in near-term prices matter a lot. For instance, using my basic example above, while the economics don’t work at flat $30 oil, assuming oil rises to $40 in year two and then $50 from year three would generate a low positive return. Those prices actually lag the consensus forecast, which averages $46 for 2021.
On the other hand, that consensus stood at $58 only two months ago, so it’s fair to say expectations can change in the middle of an unprecedented oil shock. The current list of unknowns encompasses how quickly people resume something like normality even after lockdowns ease; whether Covid-19 inflicts a second wave; how long the glut of oil inventory building now lasts; and how quickly Saudi Arabia and Russia resume a market-share strategy.
The rational thing to do is to wait for higher prices — indeed, conserving barrels, rather than pushing them into a glutted market, is a prerequisite for those higher prices. As EOG Resources Inc. said Friday, oil kept underground is “low-cost storage.”
E&P companies carrying more debt (and there are more than a few) may be stuck on the treadmill. Covenants demand cash flow today even if that means destroying value over time. But this is a reminder of why the industry finds itself vulnerable in the first place: managing to production rather than value, and thereby dragging down prices by putting more sub-economic oil onto the market. The Saudi-Russian spat in early March was a warning the market won’t just absorb that from here on. Breaking the existing shale model, and redirecting cash away from wells toward creditors and shareholders, must be one outcome from all this.
On that front, it’s worth noting the E&P sector now offers a higher dividend yield than the broader market for only the second time this decade.
E&P stocks traded at a premium on yield because they weren’t valued on yield. Unlike the majors and refiners, frackers were owned for growth and a bet on oil prices. That rationale was fraying even before Covid-19, but is especially out of favor now. The yield spread to the market needs to widen, not just to compete against both other oil stocks and other sectors. It would also be a tangible sign of fewer dollars heading into drilling. Like Gallagher said, the world doesn’t need any more of the industry’s “product” right now. That includes investors.
(1) Assumes royalties of 25% and severance taxes of 4.6% for oil and 7.5% for natural gas. G&A expenses of $2 per barrel of oil equivalent and $5 of other operating expenses.
This column does not necessarily reflect the opinion of the editorial board or Bloomberg LP and its owners.
Liam Denning is a Bloomberg Opinion columnist covering energy, mining and commodities. He previously was editor of the Wall Street Journal’s Heard on the Street column and wrote for the Financial Times’ Lex column. He was also an investment banker.
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