Who Will Wind Up Holding the Bag in the Shale Gas Bubble?

We’ve been writing off and on about how the sudden fall in gas prices has been expected to put a lot of shale gas development on hold. In fact, quite a few analysts believe that one of the big Saudi aims in refusing to support oil prices was to dent the prospects for competitive energy sources, not just renewables like wind and hydro power, but shale gas.

Even though OilPrice reported that US rig count had indeed fallen as oil prices plunged, John Dizard at the Financial Times (hat tip Scott) gives a more intriguing piece of the puzzle: the degree to which production is still chugging along despite it being uneconomical. The oil majors have been criticized for levering up to continue developing when it is cash-flow negative; they are presumably betting that prices will be much higher in short order.

But the same thing is happening further down the food chain, among players that don’t begin to have the deep pockets of the industry behemoths: many of them are still in “drill baby, drill” mode. Per Dizard:

Even long-time energy industry people cannot remember an overinvestment cycle lasting as long as the one in unconventional US resources. It is not just the hydrocarbon engineers who have created this bubble; there are the financial engineers who came up with new ways to pay for it.

And while the financial engineers will as always do just fine, lenders are another matter:

By now, though, there is an astonishing amount of debt that continues to build up on the smaller E&P companies’ balance sheets. According to Gavekal, the research group, even before the oil price plunge, aggregate debt-to-equity ratios in the smaller publicly traded energy companies are now at 93 per cent, up from around 70 per cent in 2012 and 2013, and around 50 per cent between 2005 and 2011. This in a highly cyclical industry that used to go through periodic banker-driven shakeouts and even bankruptcies.

One example is a KKR deal gone a cropper, Samson. As an aside, it is hard to think of an industry less suited to private equity investing than oil & gas development, since the companies have a great deal of operating leverage and the industry is highly cyclical. KKR apparently did not learn that lesson in bankruptcy of its giant energy play turned mega bankruptcy TXU. Or maybe it did. While the other lead investor in that deal, TPG, has had a hard time fundraising as a result of the TXU debacle, KKR has sailed on unscathed. This early November Reuters article describes how KKR is struggling to rescue this transaction*:

KKR & Co which led the acquisition of oil and gas producer Samson Resources Corp for $7.2 billion in 2011 and has already sold almost half its acreage to cope with lower energy prices, plans to sell its North Dakota Bakken oil deposit worth less than $500 million as part of an ongoing downsizing plan, according to people familiar with the matter. 

KKR, one of the world’s biggest private equity firms with $96 billion in assets under management, overpaid for Samson, and persistently low natural gas prices have hampered its ability to finance the company and added to its debt burden, the people said. KKR’s plan was to shift Samson’s assets from natural gas production more into oil and liquids. 

With U.S. crude oil futures down 25 percent since June, Samson has hired Bank of Nova Scotia (to sell the Bakken assets, and the company is contemplating more asset sales to raise cash, the people said, without specifying which other assets. 

In the medium-term, Samson may look at acquiring higher-income properties, turning to its private equity owners or external investors for financing, one of the people said.

KKR closed on Samson in November 2011. Industry experts believe one of the reasons they overpaid is they used conventional oil and gas models that showed much longer production lives for each well. Yet by spring of 2012, there were reports in conventional media about how shale gas wells have short production lives. So how could KKR have missed this issue?

In the new normal of lower energy prices, developers are apparently playing a game of chicken, hoping that competitors will cut production first. Dizard again:

Particularly in the gas and natural gas liquids drilling directed sector, every operator (and their financier) is waiting for every other operator to stop or slow their drilling programmes, so there can be some recovery in the supply-demand balance. I have been hearing a lot of buzz about cutbacks in drilling budgets for 2015, but we will not really know until the companies begin to report in January and February. Then we will find out if they really are cutting back, using their profits on in-the-money hedge programmes to keep their debt under control, and taking impairment charges on properties that did not really pay off. 

One gas-orientated industry man in Houston I know thinks that the banks are going to call a halt to the madness of permanent negative operating cash flows. “What is the timing of their borrowing base renegotiations (with the banks)? That is the most important thing; can they borrow more money?” If not, he believes drilling and producing on uneconomic terms will slow or stop, and with the high depletion rates of unconventional reserves, such as shale gas, supplies will fall and gas prices will rise.

In other words, if the industry doesn’t discipline itself, the money sources will. Or will it?

If the bankers reduce the borrowing base for the E&P companies, there could be a lot of private equity or high-yield investors with covenant-light deals to offer who might take their place. Not to mention cash-rich majors who would like to take the billions they can no longer put into Russia or Venezuela, who would not mind picking up more North American properties on the cheap.

Although Dizard does not discuss the downside directly, he sets forth a fact pattern that could lead to some ugly ends. US shale gas production needs to get to $6 per mBtu or more for players who aren’t very leveraged to get to break-even cash flow; they hope to make more two to three years after that on presumably higher prices.

But if super low interest rates keep money flowing into the shale bubble, another set of issues emerges: US production is set to considerably outstrip domestic uses:

So much gas is being developed in the Marcellus and Utica resources of the northeastern US that it really cannot be absorbed by the US market. Suzanne Minter, manager of oil and gas consulting at Bentek in Denver points out: “Over the next five years, daily production in the US is forecast to grow by more than 16bn cubic feet per day, with about 10bcf of that coming from the northeast. Of that, at least 8.5bcf has to be exported. Domestic demand does not grow enough.”

That means a lot of infrastructure like pipelines and storage facilities needs to be built. But that requires regulatory approvals and possibly government intervention. And even then, with US shale gas production projected by the IEA to peak in 2020 and fall slowly over the next decade, this extraction boom is nowhere near as durable as development of conventional oil has proven to be.

An additional question is whether investment in infrastructure will look attractive if fracking continues to be shown to have safety risks (water supply contamination, earthquakes). The New York Times just released an impressively-researched story on regulatory abuses in North Dakota. It does not make for pretty reading. And if Dizard is right, that bottom-fishers swoop in to pick up producers gone bust, headlines about bankruptcies and distress are not conducive to downstream development.

In other words, there’s a not-trivial possibility, as Dizard explains, that US production does not get throttled back much by falling oil prices, that the wall of money willing to invest in energy overcomes normal supply and demand factors. If that takes place, there could be a further leg down if US producers lack the capacity to send enough production overseas.

Now remember, Dizard already warned that smaller E&P players were already overlevered. Some, perhaps many, lenders will take losses. Private equity bottom fisher-wannabes will also come in using other people’s money. But cheaper doesn’t necessarily mean cheap enough. Recall all the sovereign wealth funds that took equity stakes in banks in 2007 thinking they had gotten a good deal.

A reader points out that this all feels a lot like the last oil boom gone bad. I’m old enough to remember how pretty much every bank in Texas was sold as a result (and that helped speed the liberalization of interstate banking, since no one in state had the wherewithall to act as a rescuer). Via e-mail:

This whole situation is very similar to the oil and gas boom of late 70′s and early 80′s. It was driven by letters of credit deals which were used to secure debt. A little bank called Penn Square Bank upstreamed those loans to Continental Illinois and Sea First in Seattle. All financed by debt and wells being drilled which were not economical. When the music stopped the debt came crumbling down taking down Continental and Sea First (two of the ten largest banks in the US) as well as many others. Many banks did not even know they were lending to oil and gas because they were lending on like real estate. Well when the oil and gas industry collapsed so did real estate. Practically every significant bank in Oklahoma and Texas failed due to this.

Is the Fed teeing up an even bigger energy boom and bust? Admittedly, several adverse scenarios have to play out in succession for the downside case to kick in. But the first one, of shale gas producers not cutting very much despite the plunge in energy prices, is already under way. One might peg the odds of a major levered energy bust at 20%. That’s still uncomfortably high for the amount of damage that would result.

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