The New York Times recently ran a series of stories that questioned the sustainability of the shale gas revolution and suggested that by focusing on initial production rates, many shale gas producers have downplayed the rapid decline rates that many wells experience. The article also questions the profitability of shale gas fields at a time when natural gas prices remain depressed and the cost of hydraulic fracturing–a technology that’s critical to unlocking hydrocarbons locked in tight reserve rock–continues to rise.

These articles undoubtedly had their intended effect, mobilizing both critics and supporters of shale gas development and stimulating a vociferous debate. Although arguments that the emperor has no clothes always attract plenty of eyeballs–the primary motivation of many media outfits–readers must evaluate the logic underpinning these claims and distinguish the rational from the sensational.

The New York Times is correct that some shale gas fields are uneconomic in the current pricing environment, which explains why drilling activity has declined in the natural gas-rich Barnett Shale and Haynesville Shale.

But the articles largely ignore the economics of the Eagle Ford Shale and other unconventional fields that produce large amounts of high-value oil, condensate and natural gas liquids such as butane, ethane and propane. In general, exploration and production firms have shifted production from dry-gas fields to liquids-rich plays that offer superior profitability. Many investors have picked up on this distinction; stocks of companies that have failed to make this transition have underperformed.

To be sure, some shale gas companies–particularly those that were late to the game or overpaid for undesirable assets–pursued flawed business strategies and fell prey to the herd mentality. As the authors of the New York Times articles point out, the industry’s approach of snapping up as much acreage as possible and then drilling madly to secure their leasehold by production and identify the most economic zones involves a number of inherent risks.

For one, although many commentators discuss these shale plays as unitary wholes, anyone who pays attention to independent producers’ quarterly results and conference calls can attest that well performance varies dramatically throughout a field. But the stampede to scoop up acreage in an emerging shale play inflates prices in even subpar areas and obligates operators to drill these plays to secure their leasehold by production.

That’s one of the reasons why producers continue to drill in gas-only fields despite unattractive economics: Many leasing contracts require operators to sink a commercially viable well within an established period to secure the acreage.

This involuntary drilling activity catalyzed a wave of joint ventures and acquisitions that have occurred in recent years–an important source of capital to support these programs. Many of the acquirers are large, integrated energy companies that boast bulletproof balance sheets and can afford to take a long-term view on natural gas prices and demand.

For example, Marathon Oil Corp (NYSE: MRO) paid $3.5 billion for 141,000 acres (about $21,000 per acre) in the Eagle Ford Shale from Hilcorp Resources Holdings LP. The deal surpassed Korea National Oil Corp paid $16,000 per acre to Anadarko Petroleum Corp (NYSE: APC) to establishing a foothold in this hot shale play.

The elevated prices that latecomers have paid for acreage illustrate the importance of being an early mover in these plays. Thisstrategy that has paid off for EOG Resources (NYSE: EOG), the leading oil producer in North Dakota, the Eagle Ford Shale and the Niobrara Shale. Lower entry prices translate into more financial flexibility and superior margins.

This approach appears to be catching on with some operators. A year and a half ago, Devon Energy Corp (NYSE: DVN) announced that it would divest its international and offshore assets to focus exclusively on North American onshore plays, primarily shale oil and gas fields and Canadian heavy-oil fields.

The sale of these properties–including its holdings offshore Brazil and in the US Gulf of Mexico–netted the company about $8 billion after taxes, some of which has been plowed into ramping up drilling activity in the Permian Basin and developing its Canadian assets. On June 28, the Devon Energy provided analysts with an update on its operations and capital spending plan, an announcement that caused a bit of a buzz in the industry.

Rather than announce acquisitions in the Eagle Ford, the Wolfberry or other hot shale plays, David Hager, Devon Energy’s head of exploration and production, unveiled five early-stage shale plays in which the company has amassed substantial acreage positions at low costs.

Here’s how Hager explained the company’s strategy:

…[O]ur objective, overall, that what we’re trying to accomplish with these new ventures plays is to get in early and to identify new plays that we think will be successful and to get in with very reasonable terms, with low acreage costs or low royalties so that when we have success, we can really have outstanding economics.

We frankly think it makes a lot more sense that we have the capability to identify potential new plays, versus paying top dollar in what are considered the hot plays today. And we think we can create a lot more value for our shareholders by doing that.

Although we covered the Niobrara Shale at length in a free article on US shale oil plays, only minimal drilling has occurred in the four other plays Hagen highlighted–the Tuscaloosa Shale in Louisiana and Mississippi, the Mississippian in Oklahoma and the Utica Shale in Ohio and Michigan. Investors and analysts will closely scrutinize Devon Energy’s second-quarter results for additional details on these fields and initial drilling results.

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