Is the shale revolution becoming a casualty of its own success?
Can American shale oil producers survive at under $60 oil?
All revolutions come with a bit of bloodletting, and it tends to involve the blood of the people who built them in the first place. So it was with the so-called “shale revolution” and one of its key architects this past November. Harold Hamm, the brash and outspoken CEO of Continental Resources, announced that he had monetized all of his company’s forward hedges through 2016 for a one-time gain of $433 million. It was a brave bet given that oil prices had already fallen 25 per cent and had yet to show any signs of finding a bottom. But Hamm, it seemed, was spoiling for a fight with OPEC, which he’d referred to just a month earlier as a “toothless tiger.” Three weeks later to the day, Ali Al-Naimi, Saudi Arabia’s minister of petroleum and mineral resources, emerged from a pivotal OPEC meeting in Vienna to announce that the cartel had decided not to cut its collective production.
The global oil market, he said, “will balance itself.” The tiger, apparently, still had some fangs left. American markets were closed for Thanksgiving, but when they reopened on Friday, shares of Hamm’s company and virtually every other American shale oil producer were drowning in red. Continental shares were down almost 20 per cent on the day (evaporating $3.8 billion in market capitalization, or almost 10 times what it had pocketed by selling its hedges) and it wasn’t even the hardest hit of the group. That dubious honor belonged to Goodrich Petroleum, whose shares were down nearly 35 per cent. If the Saudis really did refuse to cut production in order to wage a price war with shale producers, as many analysts and commentators suggested at the time, they won the first battle in decisive fashion.
The real question was, and still is, how long can shale producers like Harold Hamm’s Continental Resources survive in this new oil price environment? Opinions on that are mixed. Some, like analysts at Citigroup, have suggested that with so-called half-cycle costs as low as $35 a barrel, shale producers could dig in and wait out the OPEC assault. Others, like independent geological consultant Arthur Berman, think the true break-even price is much higher than that. “It varies from company to company and play to play, but on average I think that something in the neighborhood of $85 at the wellhead – that’s not Brent, that’s not WTI, that’s the realized price of the offer – is a reasonably good number for break-even on these plays,” he says. And, Berman says, virtually all companies are taking a discount to WTI at the wellhead, and often a double-digit one. “If the differential between whatever the standard you’re measuring and the wellhead is $10 or $12 or $15, the plays are underwater right now.”
Shane Fildes, the head of BMO’s global energy group, says that part of the challenge with accurately assessing the break-even price of the average shale oil producer is that there simply isn’t enough data yet about what a full cycle looks like. But he’s not sold on the notion that you can assess their viability at lower prices by looking at those half-cycle costs. “On a per-well basis, the type curves would suggest a certain rate of return. But when you look at the upfront land cost, the drilling and completion, the infrastructure and pipe tie-in … from soup-to-nuts, that’s when things look a little different than a half-cycle ROR [rate of return]. The best testament to that is that there’s a whole bunch of companies with triple-digit ROR projects that have, on a corporate basis, single-digit returns on equity. So you go, ‘What happened between the marginal per-well analysis and the corporate analysis?’ ”
Berman isn’t buying half-cycle economics either. “That’s a stupid way of looking at it. That’s not a realistic way of looking at it at all. That’s like me saying that if only I didn’t have to pay my mortgage and my daughter’s student loan, then my finances would look pretty good this quarter. Well, unfortunately, I do have to pay those things. This half-cycle stuff is just the silliest thing in the whole world — it doesn’t reflect any kind of reality.”
Speaking of reality, the other major concern that Fildes has is the fact that in these plays the pace never slows down – indeed, almost by definition, it can’t. “The Achilles heel of the unconventional resource sector is that there’s no end. It’s not a defined pool where once you drain it you’re done. So very rarely are you seeing something that’s an unconventional resource development that achieves payout, enters the harvest and returns capital to the original providers. It just seems to be exponential – you use that gain and invest that, plus more, to grow faster.”
That treadmill effect, Fildes says, is one that shale producers have yet to find a way to escape – and one that could be very dangerous for them if prices stay low for an extended period of time. “When you have these high-decline, multi-stage fracked horizontal wells, your aggregate treadmill goes faster [with] the bigger wedges of production you bring on every year. That just speeds the treadmill up and increases the requirement for future capital. That’s not to say it’s not economic ultimately. It’s just saying that it’s a bigger user of capital, and when we see a big price break like we’ve seen, the availability and cost of that capital changes.”
Therein lies the rub for shale producers. So far, they haven’t had much difficulty accessing capital, even if they’ve had to pay a premium in order to get it. They’ve issued plenty of equity and borrowed from the banks, but their capital source of choice has been high-yield debt. Since 2009, shale producers have floated $211 billion in bond offerings, and that flood of junk debt actually accelerated in 2014. Through the first three quarters of the year, energy companies accounted for 19 per cent of all debt offerings, up from 13.8 per cent in 2013. They’re putting all of this junk debt into the market, and levering up their balance sheets in the process, because they’re unable to fund their capital programs without it. In 2013, U.S. onshore oil producers outspent their operating cash flow by a ratio of two-to-one, or roughly $38 billion versus $19 billion. That’s a marked change from how the oil industry used to operate, Bloomberg’s Isaac Arnsdorf wrote in late October. “In 1994, drillers funded 42 per cent of their own capital spending, according to an Independent Petroleum Association of America member survey. Today, shale companies are outspending their cash flow by 50 per cent thanks to borrowed money, according to the IPAA.”
Berman says that Continental Resources, Hamm’s now hedge-less company and the biggest producer in the Bakken, is a perfect example of this. “To listen to all of their promotion, you’d think they just have to be making money hand over fist. But when you look at their six months ending June 2014, their cash from operations was $1.4 billion. Their capital expenditures were $2.1 billion. They were $700 million in the hole. Here’s a company whose debt is growing by $800 million a quarter. Those are disturbing numbers to me. They say that, at least for this one Bakken shale player, they’re going deeper and deeper into debt and spending more money than they’re making. Now, if that reflects a healthy company and a profitable play, then you gotta explain to me what I’m missing.”
If there’s a silver lining in this for shale producers, it’s that they’ve managed to drive their costs down as they’ve learned more about the plays in which they’re operating. Indeed, as prices were falling in October and November, there were plenty of people who speculated that the shale industry would emerge stronger from it because of the incentives it would create to cut costs and improve operational efficiency. But according to David Hughes, a geoscientist who spent three decades working for the Geological Survey of Canada, they’re already at the point of diminishing returns on that front. That’s because, despite marginal improvements in drilling techniques and technology, there are only so many sweet spots in a given play where they can be put to work – and producers are running out of them.
The per-well production rates in mature plays, Hughes says, foretell the future that shale oil producers can look forward to. “If you look at mature plays like the Barnett, for example, average well quality peaked in 2011,” he says. “It’s now down 18 per cent below peak. It’s certainly not because Halliburton hasn’t been selling ever-increasing technological increments. So what it’s telling you is that technology can’t make up for geology. It might be able to make bad geology a little bit better, but geology is telling the story in the Barnett.” That’s already starting to happen in the most prolific shale oil play in the world, he says. “If you look at the Eagle Ford, where they’re drilling around 3,500 wells per year, well quality on a barrels-of-oil-equivalent basis is flat. It’s been flat over 2013. So maybe technology’s getting better, but people are starting to have to drill in lower-quality parts of the play. Well quality isn’t going up. And the older the plays get, the steeper the declines in well quality will become.”
In a high oil price environment, that’s a challenge. In a low price one, it could end up being a death sentence. The impacts of lower oil prices on the already tenuous business model of shale oil producers are twofold. First, and most obviously, it will reduce the cash these companies generate from their operations. Indeed, given the parabolic nature of the average shale well’s type curve, low oil prices will be particularly devastating for the cash flows of shale producers, given that the majority of an average well’s oil is produced – and therefore sold – during its first 18 months. In essence, a shale oil well’s type curve exacerbates the impact of oil prices (both low and high) relative to other wells with more moderate decline rates.
But second, the stimulative nature of lower oil prices on the broader economy may encourage the U.S. Federal Reserve to accelerate its plans to normalize interest rates, which could make the high-yield debt that shale producers have relied upon less attractive to prospective investors. Just as near-zero rates may have pushed investors out on the yield curve into more speculative investments like high-yield energy bonds, a return to more normal rates could pull them back in. As the Houston Chronicle’s Collin Eaton noted in a November story, “Higher interest rates might make risky new bond issues by shale producers less attractive, and a flight of investor capital could leave the producers short on a commodity even more precious than oil: Cash.”
It’s unlikely that shale producers will start to default en masse on their debt obligations right away. But once their hedges start rolling off later this year, it could be a much different story if oil prices remain depressed. Deutsche Bank analysts Oleg Melentyev and Daniel Sorid warned in a recent report that if WTI stays below $60 a barrel for any extended duration, it could push as many as 30 per cent of the shale industry’s B- and CCC-rated borrowers into default. As Timothy Parker, a Baltimore-based asset manager at T. Rowe Price Group told Bloomberg in late November, “The balance sheet doesn’t matter until it matters, and then it’s the only thing that matters.”