The questionable economics of shale gas

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Shale gas is being sold to the American public as a miracle, arriving just in time to save us from peak oil. It’s an abundant new fuel supply that will be a “game-changer,” we’re told. We’ll soon be a major exporter of gas to the rest of the world. The economics of fossil fuels have been changed forever, along with our balance of trade.

But what if the business isn’t actually profitable? What if it’s really based on accounting trickery and overstated claims?

“Fracking” — extracting natural gas by drilling horizontally through dense shale, then fracturing it with high-pressure fluids — has indeed given the U.S. a nice bump in gas production. Production of dry shale gas soared ten-fold from under 0.4 trillion cubic feet (tcf) in 2003, to 4.8 tcf in 2010. Total gas withdrawals, including conventional gas, are up 16 percent since the end of 2005. Shale gas now accounts for about one-quarter of total U.S. dry natural gas production, and about 4 percent of our total primary energy supply.

Our shale gas resources, however, while much ballyhooed in the press, are far less certain. We may now have a 100-year supply of gas in America, as suggested by recent reports. . . or we may not. The U.S. consumes 24 tcf of gas per year. Currently, we only have an 11-year supply on the books: 273 tcf classified as “proved reserves,” meaning gas that is commercially producible at a 10 percent discount rate. Beyond that, there are only “probable,” “possible,” and “speculative” resources, where the gas has not yet actually been discovered, or proved to be economically recoverable. Even where we are sure that the resources exist, we do not know how much of is technically recoverable until we produce it. And as I noted two weeks ago, in the EIA’s Low Case shale gas estimate, the U.S. could become a net gas importer by 2035.

There is no doubt that we are producing a lot of gas, for the moment. But it may have come at the cost of profitability.

EBITDA: Earnings Before I Tricked the Dumb Auditor

Houston-based petroleum geologist and energy sector consultant Arthur Berman, along with petroleum engineer Lynn Pittinger, has independently studied the economics of thousands of wells in the three shale gas formations with the longest production histories — the Barnett Shale in Texas, the Fayetteville Shale in Arkansas, and the Haynesville Shale in Louisiana — and found numerous irregularities.

When the true structural costs of shale gas are fully incorporated, he says, including the costs of leasing, restimulating wells where production was flagging, and general operation and administrative overhead, operators need $8 to $9 per thousand cubic feet (mcf) to break even, assuming an 8 percent discount rate. For new development on existing leases, considering just the costs of drilling, completion and operation, operators need $5 to $6/mcf to break even. But the spot price (for immediate delivery) of gas is only $3.11/mcf today, and except for two brief moments in 2010, it has remained below $5 since February 2010. On an averaged annual basis, shale gas has been unprofitable since 2008.

If shale gas production is unprofitable, then why is there still so much drilling activity, and how are producers able to claim otherwise?

One answer to this conundrum is that operators need to keep drilling in order to hold onto their leases. If they don’t actively work the land that they spent the last several years acquiring in a buying frenzy, they lose it. The early operators in these gas formations, or “plays,” aren’t sufficiently well-funded to continue drilling at a loss; they’re simply trying to hold onto their leases long enough to flip them to larger companies at a profit. Hence the recent rash of joint ventures with deeper-pocketed players, which give the original leaseholders a way to pay off the leasing and initial drilling costs, but ultimately reduces their net asset values.

A detailed examination of the financial data bears this out. If shale gas is so profitable, then one might expect operators to pay for leasing and drilling costs out of cash flow, and pay down their debt. But quite the opposite appears to be the case. According to analysis by Bernstein Research, capital expenditures on land acquisition and new drilling exceeds cashflow (by as much as 511 percent in the worst example, Carrizo Oil & Gas) for 18 of the top shale gas producers, and they’re still heavily laden with debt.

A more direct explanation is that producers are willing to take a big gamble on shale gas in order to support their market valuations. Before the shale boom, reserves of both oil and gas had been in a decades-long trend of decline. Producers were nervous. Cash tomorrow, as represented by reserves, is almost as valuable as cash today from earnings. When production and reserves fall, the stocks of producers fall too and can trigger defaults on loans. Maintaining reserves, even while draining them, is an imperative.

In order to show profitability, shale gas operators have employed complex creative accounting. Instead of the usual “netback” calculations that clearly state the net profit per barrel of oil equivalent (or per mcf of gas) produced, in the 10-K reports filed with the SEC, one finds an intricate set of statements which would only be comprehensible to an expert accountant, not an average investor. Hedging strategies employed after 2008 have counterbalanced some of the losses on production, and major capital costs have been excluded through off-book accounting. Worse, Berman found that some operators have used variable production payment schemes to recognize borrowed cash up front, then failed to account for it as debt and actually claimed it as an asset.

The production of associated natural gas liquids, which generally command about half the price of oil, further complicates the economics. (At the 2011 average of $95 a barrel for oil in the U.S., gas sells at an enormous discount to oil, at $3.29 per million BTU, versus $16.39 for oil.) Natural gas liquids produced along with the “dry” gas have certainly helped generate revenues, but to what degree, we don’t know, since they are not separately reported to regulators. Berman estimates they might add $1/mcf after processing. Operators commingle the revenues from “dry” gas with those from associated natural gas liquids, masking the true profitability of the gas production.

Does it matter if some operators are able to drill profitably due to the natural gas liquids, but not the gas itself? Well yes, it does. If the wells are shut down after their liquids play out, it could leave a lot of gas effectively stranded, and a significant chunk of the anticipated reserves would never be produced.

We do know that many shale gas operators have been refocusing their operations on liquids-rich areas of the plays in the last few years, in order to capture the liquids premium. As fund manager Jim Hansen of Seattle-based Ravenna Capital Management pointed out to me, a slide in a November 2010 investor presentation by major shale gas producer Chesapeake Energy confirmed that it was “aggressively shifting capital to liquids-rich plays,” and reducing drilling to the level required to retain its leases and court joint venture partners, until natural gas prices rise above $6/mcf. This comports to Berman’s profitability analysis. Chesapeake’s stated strategy was to acquire large leaseholdings in liquids-rich plays, then sell a minority interest in them within one year, in order to recover the cost of the lease.

Hansen also observes that the rig count in shale operations is now down more than 50 percent from its 2008 high, casting further doubt on the idea that additional drilling is currently profitable.

In the oldest and most productive of the shale gas plays, the Barnett Shale in Texas, wells decline at an annualized rate of 44 percent, according to Berman’s research, with a steep decline rate of 65 percent in the first year and 53 percent in the next, falling gradually thereafter to around 20 percent per year. Shale gas wells typically pay out over half their total lifetime production in the first year. So operators must keep drilling continuously to maintain a flat rate of overall production. However, operators and the industry press tend to only report the high, initial flow rates of gas wells, giving investors a mistaken impression of how productive they really are. Indeed, Berman’s analysis suggests that the claimed lifetime productivity of the wells—and by extension, the reserves that operators are claiming in their SEC filings—may be overstated by over 100 percent.

Nobody expects the shale gas inquisition

As more data about these relatively young operations becomes available, it is tending more toward the more lower estimates of the skeptics than the initial estimates of the operators. For example, Berman’s analysis of wells in the Haynesville Shale suggested that they would produce about 3 billion cubic feet of gas on average, not the 6 to 10 bcf claimed by the operators — estimates which were based on the high initial productivity of the wells, without taking their lower, later output properly into account. Objective third-party research from Louisiana State University has just confirmed Berman’s estimate.

Berman, Pittinger, and Hansen are not alone in their skepticism about the profitability of shale gas. Writing in The New York Times back in June, Ian Urbina referenced numerous emails and internal documents from industry insiders who were skeptical about the claims made by operators. Industry defenders countered that the skeptics are outsiders, and dismissed their findings out of hand (with, I will note, some fairly specious arguments). But new scrutiny is now being applied to the claims of producers. New York Attorney General Eric Schneiderman is now investigating Marcellus Shale operators, including Range Resources, Cabot Oil & Gas Corp, and Goodrich Petroleum, specifically to see if they have overstated the productivity of their wells. And the SEC has issued dozens of EDGAR filings to shale gas companies to shale gas companies, questioning their methodology on reserves calculations, accounting of development expenses, and other formal disclosures.

If all of this is beginning to sound a bit Ponzilicious, it should, particularly if the anticipated future production and profitability don’t materialize. But that doesn’t mean it’s a fraud, and Berman is quick to point out that all of the accounting employed by shale gas producers is perfectly legal. On the other hand, so were the mortgage-backed securities, the credit default swaps leveraged on those securities, and other financial weapons of mass destruction that would have brought down the global financial system in 2008, if the Fed and the Treasury hadn’t intervened by debasing the U.S. dollar.

Now, it’s certainly possible that the story of shale gas will unfold in an orderly, totally legal manner. Some of the wildcatters could make out nicely on their debt-fueled land grab, while others go bankrupt. The bigger players who later acquire the leases could produce gas at a loss for years before gas prices rise again and put them in the black on their bets. That’s just capitalism.

But it’s also possible that early players simply took advantage of the uncertainty about a new resource and sold their operations like pigs in a poke, and that we’ll find ourselves holding a fleet of shiny new CNG trucks and gas-fired power plants just as the shale gas phenomenon flares out.

The uncomfortable truth is that, at this point, we simply don’t know how big our shale gas resources are, how much of the gas can be technically or economically produced, or how profitable producing the gas actually is. And that should give us pause. Apart from the rancorous debate over the environmental impact of shale gas fracking, we would do well to consider how much faith we’re placing in the questionable economics of shale gas, and how much of our future we’re betting on it.

http://www.smartplanet.com/blog/energy-futurist/the-questionable-economics-of-shale-gas/243