Bernstein Research senior E&P analyst Ben P. Dell says natural gas companies' presentations and quarterly reports remain inconsistent. Shale-drilling economic measures are still unclear.

“Either E&Ps are being selective in their disclosure, telling investors about the best wells, and ignoring all the sunk costs/infrastructure costs,” says Dell, “or alternatively it suggests that backward-looking costs are materially higher and, hence, investors should prepare for a secularly declining gas price.”

The analyst says shale-play E&P companies should be making tons of money based on EUR’s and implied F&D, but few companies are capable of matching per-well guidance to annual reports.

“In presentations, companies continue to guide towards F&D and overall costs which would imply incredible economics at $7 or $8/Mcf gas and strong returns at far lower prices.”

Dell says some suggest shale plays have structurally lowered the U.S. cost curve and natural gas will never reach $7/Mcf again.

Haynesville management teams fail to account and report acreage costs acquired in low-production parts, lease reacquisition, cost of failed wells and the EUR unproductive wells, he adds.

“For example it appears that, to the north, the Haynesville could yield as little as 1 to 3 Bcf per well, which would materially pull down the average EUR within the play or it could mean that a proportion of the play is uneconomic. However, few companies discuss those wells publicly.”

Core parts of the play and uneconomic parts are reported differently. “…By covering E&Ps in the core part of the play we, by definition, see a better-than-average well set. In addition, the additional wells drilled in plays that are uneconomic or in nonproductive parts of the play are rarely taken into account when averaging EUR per well.”

This raises questions of how investors should determine the U.S. cost curve, he says. Elasticity and cost base of the U.S. should be, in principle, congruent with companies making up that particular industry.

“Those companies with the highest cost bases should see the biggest percentage drop in rig count as their wells become economic. In addition, those plays with the highest costs should see the steepest reduction in rig count.”

Dell says, as a result, one can assume plays with relatively higher costs have seen drilling fall. However, he says two cases break this assumption.

“First, if a company has pledged to meet a production target it may drill, regardless of returns. Second, if lease expirations are short, companies could face a use-or-lose dilemma, leading them to drill uneconomic wells.”

Thus, the same is falsely implied for companies with higher rig counts, he says. The higher the rig count, the lower the cost base should be.

He and his colleagues collected data on the U.S. land-rig counts of the major gas operators over the past 15 months to see if these conclusions were true. Data was collected for Anadarko Petroleum Corp., Chesapeake Energy Corp., Chevron Corp., Cimarex Energy Co., Devon Energy Corp., El Paso Corp., EnCana Corp., EOG Resources Inc., Forest Oil Corp., Newfield Exploration Co., Petrohawk Energy Corp., Pioneer Natural Resources, Range Resources Corp., Questar Corp., Quicksilver Resources Inc., Southwestern Energy Co., Ultra Petroleum Corp., Whiting Petroleum Corp. and XTO Energy Inc.

“…As the gas price has declined, many of the operators have scaled back their operations significantly. More importantly, as would be expected, the highest-cost players have seen the biggest percentage decline while the lower-cost players have seen more moderate changes.”

The same is true for various U.S. plays. He says a high cost base should lead to less activity and a drop in rig count.

“For example, while the Fayetteville has unsurprisingly not seen a big drop—despite no lease issues—the Woodford has seen a bigger decline and the Barnett a bigger drop still,” says Dell, “implying that the Barnett is higher cost than the Woodford, which is higher cost than the Fayetteville.”

Not all shale plays are high cost. The Fayetteville has seen one of the smallest declines and the Marcellus and Haynesville are both positive. However, the largest shale play, the Barnett, is not profitable to run many rigs at this time.

“Indeed, as shale becomes an ever-larger part of U.S. gas, it makes sense that different shales will occupy different positions on the cost curve,” Dell says. “(The data) doesn't show that all shales are low cost, or even that the average shale is that much better, on average, than the average gas well.”

-- Brian Brooks