Proximity to active tectonic boundaries can be one of the most important factors controlling treatment and wellbore designs. In this case study, the initial estimate of SHmax was not nearly as large as that required to explain the observed flaws in design and the associated costs. Wells and completions were designed to typical Texas standards where normal stress regime is the norm. However, textbook “hydraulic” fractures were not observed and the majority of the stimulation reactivated large-scale faults. Geomechanical analysis of observed focal mechanisms reveals a very different stress regime that explains the constant screen outs and casing deformations. Focal mechanisms observed during the stimulation were evaluated to determine a theoretical stress state that best-fit the majority of the focal mechanisms. The main dip-slip focal mechanism has two nodal planes that are equally possible. Each nodal plane was evaluated based on temporal and spatial hypocenter propagation characteristics as well as the failure potential using both the sonic- and microseismic-derived stress models. In addition, the wellbore stability was evaluated to understand which nodal plane and stress model predicted the casing deformation with highest precision. Concerning focal mechanism nodal planes, the shallow-dipping planes became the obvious choice based on the 3D alignment of event locations. In addition, the shallow-dipping planes were most susceptible to failure using the microseismic-derived stress model. Under these conditions, faults required <<300 psi of net pressure, which was observed during the stimulation. The sonic-derived stress model would not have predicted the casing collapse observed along one of the wells. In conclusion, the microseismic stress model shows that drilling oblique to SHmax can results in an increase in wellbore stability.