This dissertation is composed of three papers in the field of energy economics. The first paper estimates revenue and technical efficiency for more than 11,000 wells that were drilled in the Barnett between 2000 and 2010, and also examines how the efficiency estimates differ among operators. To achieve this objective, we use stochastic frontier analysis and a two-stage semi-parametric approach that consists of data envelopment analysis in the first stage and a truncated linear regression in the second stage. The stochastic frontier analysis (SFA) and data envelopment analysis (DEA) commonly identify only two operators as more revenue and technically efficient than Devon, the largest operator in the Barnett. We further find that operators have generally been effective at responding to market incentives and producing the revenue-maximizing mix of gas and oil given the reigning prices. Furthermore, coupled with this last result is the insight that most of the revenue inefficiency is derived from technical inefficiency and not allocative inefficiency.
The second paper uses multilevel modeling to examine relative operator effects on revenue generation and natural gas output during the 2000-2010 period. The estimated operator effects are used to determine which operators were more effective at producing natural gas or generating revenue from oil and gas. The operators clump together into three groups – average, below average, and above average – and the effects of individual operators within each group are largely indistinguishable from one another. Among the operators that are estimated to have above average effects in both the gas model and the revenue model are Chesapeake, Devon, EOG and XTO, the top four largest operators in the Barnett. The results also reveal that between-operator differences account for a non-trivial portion of the residual variation in gas or revenue output that remains after controlling for well-level characteristics, and prices in the case of the revenue model.
In the third paper, we estimate an econometric model describing the decline of a “typical” well in the Barnett shale. The data cover more than 15,000 wells drilled in the Barnett between 1990 and mid-2011. The analysis is directed at testing the hypothesis proposed by Patzek, Male and Marder (2014) that linear flow rather than radial flow – the latter of which is consistent with Arps (1945) system of equations – governs natural gas production within hydraulically fractured wells in extremely low permeability shale formations. To test the hypothesis, we use a fixed effects linear model with Driscoll-Kraay standard errors, which are robust to autocorrelation and cross-sectional correlation, and estimate the model separately for horizontal and vertical wells. For both horizontal and vertical shale gas wells in the Barnett, we cannot reject the hypothesis of a linear flow regime. This implies that the production profile of a Barnett well can be projected – within some reasonable margin of error – using the decline curve equation of Patzek, Male and Marder (2014) once initial production is known. We then estimate productivity tiers by sampling from the distribution of the length normalized initial production of horizontal wells and generate type curves using the decline curve equation of Patzek, Male and Marder (2014). Finally, we calculate the drilling cost per EUR (expected ultimate recovery) and the breakeven price of natural gas for all the tiers.